Bonavista Energy Corporation Announces 2016 First Quarter Results

CALGARY, ALBERTA--(Marketwired - May 5, 2016) - Bonavista Energy Corporation ("Bonavista") (TSX:BNP) is pleased to report to shareholders its financial and operating results for the three months ended March 31, 2016. Operating and cash costs improved to $5.75 per boe and $9.45 per boe in the first quarter of 2016 resulting in a 18% and 14% improvement relative to the prior year period, supporting Bonavista's emphasis on cost reductions and efficiency improvements. The unaudited financial statements and notes, as well as management's discussion and analysis, are available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at http://www.sedar.com and on Bonavista's website at www.bonavistaenergy.com.

MESSAGE TO SHAREHOLDERS

Weak commodity prices throughout the first quarter of 2016 have significantly curtailed activity levels across the Western Canadian Sedimentary Basin. For Bonavista, reduced and concentrated development spending has resulted in continued improvement in capital and operating efficiencies that has generated operating and financial results exceeding our expectations. Production of 73,180 boe per day was above our guidance, while our capital spending of $45.7 million was approximately 10% below our budget.

Our costs continue to improve substantially. The average cost to drill and complete our wells during the first quarter was $2.8 million, a 27% improvement from the first quarter of 2015, notwithstanding drilling deeper and longer horizontal wells. When analyzed on a per meter of horizontal length drilled, we have experienced a 45% reduction versus the same period last year. Similarly, first quarter operating costs have decreased 18% to $5.75 per boe and general and administrative costs on an absolute basis have improved 19% to $6.9 million, resulting in total cash costs of $9.45 per boe, a 14% improvement over the first quarter of 2015.

AECO natural gas pricing remains low as a result of high natural gas storage levels due to mild winter weather across North America. With the current pricing forecast at approximately $1.50 per gj for June through August, we will curtail approximately 2,900 boe per day of natural gas production from May to December 2016. We are also delaying our development program until natural gas prices improve in the latter half of 2016, notwithstanding the significant accomplishments we have achieved with our cost structure. We expect that these measures will impact annual production by approximately 3,000 boe per day, however we do not expect it will have a significant impact on our funds from operations based upon forecasted pricing for the remainder of the year.

Operational and financial accomplishments for the first quarter of 2016 include:

• Reduced first quarter operating costs to $5.75 per boe from $6.99 per boe and cash costs to $9.45 per boe from $10.95 per boe, representing an improvement of 18% and 14% respectively, relative to the same period in 2015;
  
  
• Reduced our exposure to the AECO index by diverting the sale of approximately 10% of our natural gas production to the U.S. mid-west market;
  
  
• Executed a capital spending program including acquisitions and divestitures ("A&D") of $45.7 million, being 77% of funds from operations generated in the quarter and a 55% reduction relative to the same period in 2015. Exploration and development ("E&D") expenditures totaled $40.6 million, drilling 12 (10.8 net) wells and generating 73,180 boe per day of production in the first quarter;
  
  
• Generated funds from operations of $59.3 million ($0.27 per share), in a quarter where realized natural gas, natural gas liquids and oil prices on a per boe basis and overall production revenues decreased by 24% and 36% respectively, when compared to the same period in 2015;
  
  
• Enhanced our commodity hedge portfolio resulting in:
  
  
• Approximately 233,000 gjs per day of natural gas hedged at an average floor price of $3.12 per gj at AECO for the remainder of 2016 and approximately 124,300 gjs per day at an average floor price of $3.06 per gj for 2017;
  
  
• Approximately 2,800 bbls per day of oil hedged at an average floor price of CDN$77.07 per bbl WTI for the remainder of 2016 and approximately 1,500 bbls per day at an average floor price of CDN$66.08 per bbl WTI for 2017; and
  
  
• Approximately 1,300 bbls per day of propane hedged at 40% of U.S. WTI pricing for the remainder of 2016 and 250 bbls per day at 40% of U.S. WTI pricing for 2017.
  
  
• Overall, for the remainder of 2016, Bonavista has approximately 86% of budgeted natural gas volumes and 73% of budgeted oil volumes hedged.
  
  

2016 YEAR-TO-DATE CORE AREA HIGHLIGHTS

WEST CENTRAL CORE AREA

Our West Central core area draws its strength from a low capital cost structure, resilient economics and consistent results. With over 900,000 net acres and approximately 800 drilling locations in our key plays, our West Central core area represents both reliable low risk drilling opportunities and promising new key plays. We have built an extensive network of infrastructure to support our continued development of this core area, including 2,800 kilometers of pipelines and 38 facilities, the majority of which are operated by Bonavista.

In the first quarter, we spent $17.5 million on E&D activities, which included drilling eight (6.8 net) horizontal wells, supporting first quarter production of 46,659 boe per day. We are planning on E&D spending of $52.5 million drilling 17 (15.4 net) Glauconite and Falher wells for the remainder of 2016.

Glauconite Natural Gas

We drilled five (3.8 net) horizontal wells, four at Hoadley and one at Strachan in the first quarter of 2016, resulting in production of approximately 23,500 boe per day. Challenging natural gas liquids pricing, in particular negative propane pricing, has resulted in the redirection of approximately 1,500 boe per day from the Rimbey facility to the Bonavista-operated Ferrybank processing facility. Current operating costs at Hoadley are approximately $4.00 per boe and are being positively impacted by the lower operating cost structure at this facility. Improvements in operating costs combined with the higher heat content of the natural gas are resulting in incremental operating income despite lower recovery rates.

First quarter Hoadley Glauconite drilling and completion costs were $1.9 million per well, a 27% improvement relative to the same prior year period. We have also experienced a 24% decrease in the drilling and completion costs for our first quarter Strachan Glauconite wells, relative to the prior year's period.

With an inventory of approximately 350 locations, the Glauconite allows for many years of predictable development. We plan to drill 14 (12.4 net) horizontal wells for the remainder of 2016.

Spirit River Falher Natural Gas

We drilled three (3.0 net) Falher wells at Morningside in the first quarter of 2016, all of which exceeded our type curve. Our first quarter program was designed to extend the boundaries of our Falher play to the south of our main development area. With average first quarter drill and complete costs of $1.7 million, a 26% improvement from the same period last year, the Morningside Falher play remains competitive with the top tier development plays in western Canada.

We expect our production to grow 16% in 2016 while spending 75% of the net operating income from the play. Current production is approximately 4,100 boe per day. We plan to drill 3 (2.9 net) wells for the remainder of 2016.

DEEP BASIN CORE AREA

In this liquids-rich natural gas core area we have established a net land position of approximately 295,000 acres and continue to increase our inventory through swap and acquisition transactions. We currently have over 300 horizontal drilling locations of which approximately 45% are extended reach laterals. We also own and operate our infrastructure, resulting in significant cost reductions and incremental egress.

In the first quarter, we spent $21.2 million on E&D activities drilling four (4.0 net) horizontal wells supporting first quarter production of 19,809 boe per day. Our 2016 program is focused on our Wilrich play with 10 (10.0 net) wells planned at Ansell and one (0.8 net) wells planned in the Bluesky at Pine Creek. E&D spending of $36.0 million is contemplated for the remainder of 2016.

Spirit River Wilrich Natural Gas

We drilled four (4.0 net) Wilrich wells in the first quarter of 2016, all of which were extended reach wells. Our drilling results exceeded our expectations, with drilling and completion costs averaging $3.9 million per well, a 15% improvement from the same period last year despite the first quarter 2015 wells being only one mile horizontal wells.

We continue to expand our Wilrich asset base. During the first quarter, we acquired approximately 600 boe per day of Wilrich production for $5.2 million. These assets are expected to add eight incremental drilling locations to our prospect inventory.

Our compression and processing facility at Ansell is reaching its capacity of 60 mmcf per day. Since commissioning our facility in the third quarter of 2015, we have reduced our operating costs by 32% to $2.75 per boe. The facility, which is connected to both the TransCanada and Alliance pipelines, is expandable to 120 mmcf per day. However, no significant infrastructure spending is planned for 2016.

Similar to prior years, spring break-up will curtail all our activity in this area during the second quarter. We plan to drill 6 (6.0 net) wells for the remainder of 2016, with current production being approximately 12,900 boe per day.

STRENGTHS OF BONAVISTA ENERGY CORPORATION

Throughout our nineteen year history, from an initial restructuring in 1997 to create a high growth junior exploration company, through the energy trust phase between July 2003 and December 2010, to a dividend paying corporation, Bonavista has remained committed to the same operating philosophies despite the endless commodity price volatility and uncertainty inherent in the energy sector. We have consistently maintained a high level of profitable investment activity on our asset base. This activity stems from the expertise of our people and their entrepreneurial approach to design profitable development projects with resilience to an unpredictable commodity price environment. Our experienced technical teams have a thorough understanding of our assets and the reservoirs within the Western Canadian Sedimentary Basin as they exercise the discipline and commitment required to deliver long-term value to our shareholders. The core operating and financial principles that guide our people have been with our organization from the beginning and remain solidly intact today.

As a result of our successful non-core disposition strategy over the past couple of years, our production and development activity is now largely concentrated in two core areas in central Alberta. We create opportunity through undeveloped land purchases, asset swaps, 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 and economics 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 high quality 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.

OUTLOOK

Western Canada and U.S. natural gas storage levels remain at the top of the five year range. This surplus of natural gas supply continues to be a challenge for North American natural gas pricing. Additionally, the AECO differential has significantly increased due to strong production from Canadian producers and reduced eastern Canadian demand, as evidenced by a decrease in firm contract volumes on the TransCanada Pipelines mainline. At current AECO prices, most natural gas development opportunities in the Western Canadian Sedimentary Basin are economically challenged.

With continued pressure on western Canadian natural gas pricing, significantly lower development activity and curtailed production due to economics, we expect Canadian natural gas storage levels to retreat towards normal levels. This should bring supply and demand into balance and strengthen western Canadian natural gas pricing this fall.

We remain protected from this price volatility in 2016 with approximately 86% of our budgeted natural gas volumes hedged at CDN $3.12 per gj for the remainder of the year. We do not anticipate selling any of our natural gas at AECO daily prices this summer. In addition to our hedging program, we have diversified away from the western Canadian market by diverting approximately 10% of our budgeted natural gas volumes for 2016 to the U.S. mid-west market. This pricing is currently at a 90% premium to AECO pricing.

Our 2016 capital budget remains unchanged at $140 to $145 million, which is expected to result in drilling approximately 36 (32.9 net) wells. With a desire to preserve our reinvestment economics, we have deferred the drilling and completion of certain wells to the second half of the year. This deferral, coupled with the curtailment of approximately 2,900 boe per day of natural gas production, will result in average production for 2016 of between 66,000 and 69,000 boe per day. This level of production will generate funds from operations of between $225 and $235 million at current forecasted commodity prices. When added to our dividend payments, this capital budget will result in a conservative payout ratio of below 70%, leaving between $70 and $80 million to be used towards debt repayment. We remain focused on improving our financial flexibility, continuing to rationalize non-core assets and concentrate our capital spending in two core areas. We will remain responsive with our capital budget should commodity prices improve in the second half of the year.

Ms. Magni Lake and Mr. Cory Stewart resigned as Vice President, Marketing and Vice President, Land, respectively. On behalf of Bonavista, we thank them for their service and commitment and wish them all the best in their future endeavors.

We thank our employees for their dedication and commitment through these challenging times and our shareholders for their continued support.

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 dividend paying energy corporation focused on the efficient development of high quality oil and natural gas assets while providing sustainable value to shareholders.