Bonavista Energy Corporation
TSX : BNP

Bonavista Energy Corporation

July 26, 2016 17:00 ET

Bonavista Energy Corporation Announces 2016 Second Quarter Results

CALGARY, ALBERTA--(Marketwired - July 26, 2016) - 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, 2016. Operating and cash costs improved to $5.58 per boe and $9.51 per boe in the second quarter of 2016 resulting in a 21% and 16% 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.

Highlights
Three months ended June 30, Six months ended June 30,
2016 2015 % Change 2016 2015 % Change
Financial
($ thousands, except per share)
Production revenues 90,908 150,110 (39 )% 195,386 314,397 (38 )%
Funds from operations(1) 59,507 96,004 (38 )% 118,837 193,152 (38 )%
Per share(1) (2) 0.27 0.44 (39 )% 0.54 0.89 (39 )%
Dividends declared 2,486 21,546 (88 )% 8,907 43,084 (79 )%
Per share 0.01 0.11 (91 )% 0.04 0.210 (81 )%
Net loss (101,012 ) (1,882 ) (5,267 )% (54,591 ) (80,742 ) 32 %
Per share(3) (0.45 ) (0.01 ) (4,400 )% (0.25 ) (0.37 ) 32 %
Adjusted net income (loss)(4) (42,798 ) 21,487 (299 )% (19,369 ) (49,134 ) 61 %
Per share(3) (0.19 ) 0.10 (290 )% (0.09 ) (0.23 ) 61 %
Total assets 3,386,563 4,362,227 (22 )%
Long-term debt, net of working capital 1,031,381 1,158,488 (11 )%
Long-term debt, net of adjusted working capital(5) 1,044,721 1,233,409 (15 )%
Shareholders' equity 1,601,173 2,244,420 (29 )%
Capital expenditures:
Exploration and development 22,603 57,854 (61 )% 63,225 169,805 (63 )%
Acquisitions, net of dispositions 65 (6,271 ) 101 % 5,103 (15,928 ) 132 %
Weighted average outstanding equivalent shares: (thousands)(3)
Basic 224,473 216,810 4 % 221,576 216,757 2 %
Diluted 229,095 220,513 4 % 226,125 220,396 3 %
Operating
(boe conversion - 6:1 basis)
Production:
Natural gas (mmcf/day) 279 332 (16 )% 290 350 (17 )%
Natural gas liquids (bbls/day) 17,027 13,133 30 % 17,732 15,090 18 %
Oil (bbls/day)(6) 3,962 5,269 (25 )% 4,264 5,888 (28 )%
Total oil equivalent (boe/day) 67,561 73,736 (8 )% 70,370 79,345 (11 )%
Product prices:(7)
Natural gas ($/mcf) 2.95 3.61 (18 )% 2.97 3.53 (16 )%
Natural gas liquids ($/bbl) 18.41 30.48 (40 )% 17.19 28.10 (39 )%
Oil ($/bbl)(6) 59.60 82.98 (28 )% 56.44 77.24 (27 )%
Operating expenses ($/boe) 5.58 7.05 (21 )% 5.67 7.02 (19 )%
General and administrative expenses ($/boe) 1.09 1.22 (11 )% 1.06 1.16 (9 )%
Cash costs ($/boe)(8) 9.51 11.32 (16 )% 9.48 11.12 (15 )%
Operating netback ($/boe)(9) 12.67 17.21 (26 )% 12.18 16.26 (25 )%

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.
  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 June 30, 2016 March 31, 2016 December 31, 2015 September 30, 2015
($ per share, except volume)
High 3.77 3.28 4.25 6.80
Low 2.23 0.94 1.60 2.93
Close 3.30 2.62 1.82 3.07
Average Daily Volume - Shares 1,492,555 1,317,618 1,210,201 1,047,494

MESSAGE TO SHAREHOLDERS

Our primary goal in 2016 of improving our financial flexibility has been met with much success year-to-date. Material steps that we have taken include an equity financing, a conservative capital budget, improved capital and operating efficiencies and continued asset concentration.

On June 17th, we completed a bought deal equity financing resulting in net proceeds of $110 million raised to strengthen our balance sheet. Our conservative capital expenditure program, significant commodity hedge positions and prudent payout ratio has resulted in a surplus of $41.6 million of funds from operations in the first six months of the year to be used for debt repayment. We expect this surplus to grow to approximately $140 million by the end of this year.

Year-to-date, our operating costs per boe are 19% lower than the same period in 2015, and our costs per lateral meter drilled have averaged 32% less while adding 39% more production per well in the first 90 days of production for wells completed year-to-date when compared to the same period last year.

We have further concentrated our asset base in 2016 with both acquisitions and divestitures ("A&D"). We have acquired 650 boe per day in our core areas and have divested of approximately 1,200 boe per day of non-core assets year-to-date. Net proceeds for all A&D transactions, is approximately $50.2 million.

Collectively, these initiatives when coupled with our plans to monetize a portion of our foreign exchange contracts will result in a forecasted year-end net debt of approximately $980 million. When compared to the amount of $1,311 million at December 31, 2015, this translates to a 25% reduction in our debt in 2016, a meaningful step in enhancing our financial flexibility.

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

  • Completed the equity financing of 34.3 million common shares for net proceeds of approximately $110 million;

  • Reduced second quarter operating costs to $5.58 per boe from $7.05 per boe and cash costs to $9.51 per boe from $11.32 per boe, representing an improvement of 21% and 16% respectively, relative to the same period in 2015;

  • Executed an exploration and development ("E&D") capital spending program of $22.6 million, being 38% of funds from operations generated in the quarter and a 61% reduction relative to the same period in 2015. Total expenditures including A&D for the quarter were $22.7 million;

  • Drilled 10 (9.7 net) wells and generated 67,561 boe per day of production in the second quarter, notwithstanding 2,700 boe per day of shut-in production, due to economics at current prices, and the delay of completion activities on all second quarter wells to the third quarter;

  • Generated funds from operations of $59.5 million ($0.27 per share) which resulted in $34.3 million of debt repayment net of our total expenditure program and dividend commitment;

  • Hedged an additional US$103.5 million of our principal payments on our US dollar denominated senior unsecured notes at a foreign exchange rate of 1.28 CDN$/US$; and

  • Enhanced our commodity hedge portfolio resulting in:

    • Approximately 224,200 gjs per day of natural gas hedged at an average floor price of $3.14 per gj at AECO for the remainder of 2016;

    • Approximately 3,500 bbls per day of oil hedged at an average floor price of CDN$76.19 per bbl WTI for the remainder of 2016;

    • Approximately 1,600 bbls per day of propane hedged at 42% of U.S. WTI pricing for the remainder of 2016;

    • Overall, for the remainder of 2016, Bonavista has approximately 75% of budgeted natural gas volumes and virtually all of our budgeted oil volumes hedged; and

    • In addition, for 2017 we have 136,600 gjs per day of natural gas hedged at an average floor price of $3.03 per gj at AECO and 2,750 bbls of oil hedged at an average floor price of CDN$63.07 per bbl WTI.

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 approximately 900,000 net acres and approximately 800 drilling locations in our key plays, this 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.

During the first half of 2016, we spent $36.8 million on E&D activities, which included drilling 18 (16.5 net) horizontal wells, supporting production rates averaging 43,213 boe per day. Ten of the 18 wells have yet to be completed and brought on production. We are planning on E&D spending of $32.2 million drilling nine (7.5 net) Glauconite and Falher wells for the second half of 2016.

Glauconite Natural Gas

We drilled nine (8.7 net) horizontal wells, eight (7.7 net) at Hoadley and one (1.0 net) at Strachan in the second quarter of 2016, bringing our total first half activity to 14 (12.5 net) horizontal wells. Given weak natural gas pricing throughout the second quarter, we have delayed the completion of these wells to the third quarter of this year.

Our first quarter Glauconite program of five (3.8 net) horizontal wells are continuing to perform above expectations with a combined average rate of 415 boe per day per well after being on-stream for an average of 140 days.

Our Glauconite play draws its strength from its low capital costs and efficient operating cost structure. Drilling costs improved in the second quarter, as Hoadley Glauconite drilling costs averaged $1.5 million, a 14% improvement relative to the same prior year period.

The Glauconite continues to exhibit predictable and resilient economics. Our inventory of over 300 locations translates to over 10 years of development at double the drilling activity of this year. We plan to drill six (4.5 net) wells during the second half of 2016.

Spirit River Falher Natural Gas

We drilled one (0.9 net) Falher well at Morningside during the second quarter. Similar to the Glauconite, we have deferred the completion of this well to the third quarter of this year to benefit from improved commodity prices at its peak production performance. Capital cost reductions have continued to improve our efficiencies, our drilling costs have improved 14% as compared to the prior year quarter.

The Morningside Falher has the best economics of our portfolio with an internal rate of return of 40% to 50% at current 2017 AECO strip pricing of $2.80 per gj and remains competitive with the top plays in western Canada. We expect it will be a driver of production growth for us in 2017 as the economics of the wells drilled on crown acreage will benefit from the Modernized Royalty Framework. To capture this economic benefit, we will defer the majority of our Falher program until 2017 and will focus on the development of our crown acreage.

DEEP BASIN CORE AREA

In this liquids-rich natural gas core area we have established a net land position of over 290,000 net 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 low cost operations and egress optionality.

Similar to prior years, spring break-up has curtailed all of our activity in this core area in the second quarter. During the first half of 2016, we spent $22.9 million on E&D activities drilling four (4.0 net) horizontal wells supporting production rates averaging 18,845 boe per day. Our second half 2016 program will be largely focused on our Wilrich play with eight (8.0 net) wells planned at Ansell and three (2.1 net) wells planned in the Bluesky at Pine Creek. We are planning on E&D spending of $48.9 million for the second half of 2016.

Spirit River Wilrich Natural Gas

Our first quarter extended reach drilling program is performing at average rates of approximately 760 boe per day per well, representing a 26% increase over the initial 90 day production period relative to the same period of our first quarter 2015 program.

We are enhancing our productivity and economics by drilling longer horizontal laterals, adjusting the design of our drilling program and modifying the completion strategy of our 2016 Wilrich wells.

The Wilrich play at Ansell will be key to our future growth in the Deep Basin. We own and operate our infrastructure where our operating costs have declined 32% to $2.75 per boe since commissioning our facility in the third quarter of 2015. We also have egress optionality with connections to both the TransCanada and Alliance pipelines. We are forecasting to expand our processing capability to 120 mmcf/d in 2017 to accommodate our future development.

Our drilling program at Ansell will continue in the third quarter and will include the drilling of a "two-mile" well on the Wilrich acreage acquired earlier this year. We plan on spending $38.2 million in the second half of the year.

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.

Our production and development activity is largely concentrated in two core areas in Alberta. 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 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 eight percent of the equity of Bonavista, aligning our interests with those of external shareholders.

OUTLOOK

The oversupply of natural gas in North America coupled with weak demand through a mild winter has led to a difficult start to 2016. This is evidenced by an average AECO natural gas price of $1.51 per gj in the first six months of the year, the lowest level for this term in 20 years. Nonetheless, recent changes in the fundamentals of supply and demand have resulted in an improved outlook. The excessive storage levels that have accumulated this past winter have been consumed at record rates in May and June due to growth in electrical generation and export demand. In addition, U.S. natural gas production estimates have fallen 1.7 bcf to average 72.9 bcf per day in June, down from its peak of 74.6 bcf per day in the first quarter.

Alberta natural gas demand has also improved, as oil sands operations have normalized after disruptions caused by wildfires. This demand strength has been complimented by a moderation of supply due to industry production curtailments. The AECO spot natural gas price has demonstrated immense volatility over the past six months ranging from a first quarter low of $0.92 per gj to a second quarter high of $2.36 per gj. With these changes to natural gas fundamentals, we expect continued price strength for the balance of this year.

Oil prices have demonstrated similar volatility. Global supply disruptions and curtailed drilling activity have supported a 95% increase in the price of WTI oil from a first quarter low of US$26.21 per bbl to a second quarter high of US$51.23 per bbl. Notwithstanding the recent retreat to the low US$40's, this oil price recovery has improved the outlook for natural gas liquids pricing. As a result, we see our realized propane price improving from $0.11 per bbl in the first quarter to a forecast of $7.00 per bbl in the fourth quarter of this year. These commodity price improvements have resulted in prudent optimism, as we schedule our activities for the second half of 2016 and begin to plan for 2017.

Given the recent strength in commodities relative to our outlook in May, and our consistent improvements in capital and operating efficiencies, we are encouraged with the economics of our development program at current commodity prices and industry conditions. As a result, we have accelerated the completion activities of the ten wells we drilled in the second quarter by approximately 30 days. In addition, we will increase our 2016 E&D capital budget by approximately 12% to between $145 to $155 million which, net of acquisitions and divestitures, will result in total capital spending of between $90 and $110 million for 2016. Notwithstanding the net disposition of approximately 1,200 boe per day subsequent to the quarter, and current shut-in volumes of 3,300 boe per day due to economics, we expect production to steadily increase for the remainder of this year as we approach our upgraded forecast of 70,000 boe per day for January, 2017. Average production for 2016 will remain at our previously disclosed guidance of between 66,000 and 69,000 boe per day. This will result in funds from operations of between $250 and $260 million at current forecasted commodity prices and will generate approximately $140 million in excess of our capital and dividend commitments, for debt repayment. Based on our current forecast of net capital spending, our total payout will be 44% of funds from operations. We will continue to remain flexible with our budget to capitalize on further improvements in commodity prices during the second half of the year.

Mr. Glenn Hamilton will retire from Bonavista effective August 1, 2016. Mr. Hamilton has been with Bonavista for 18.5 years and has contributed greatly to the success of the organization. Mr. Hamilton served in a senior financial capacity from 1998 to 2003 and as Senior Vice President and Chief Financial Officer from 2006 to 2015. As part of our succession plan, in May 2015 Mr. Hamilton stepped down as Chief Financial Officer continuing with Bonavista as a corporate advisor to senior management. We wish Mr. Hamilton much success in the next chapter of his life.

We thank our employees for their dedication and our shareholders for their trust and support. We are confident that our strategies will continue to strengthen Bonavista through this environment and look forward to delivering profitable growth from our quality asset base.

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.

Contact Information

  • Bonavista Energy Corporation
    Keith A. MacPhail
    Executive Chairman
    (403) 213-4300

    Jason E. Skehar
    President & CEO
    (403) 213-4300

    Dean M. Kobelka
    Vice President, Finance & CFO
    (403) 213-4300
    www.bonavistaenergy.com