(TSX:BNP)
CALGARY, July 31, 2018 /CNW/ – Bonavista Energy Corporation (“Bonavista”) is pleased to report to shareholders its financial and operating results for the three and six months ended June 30, 2018. In the second quarter of 2018 we generated adjusted funds flow of $65.7 million, allocating $29.0 million to a reduction in total net debt. The unaudited financial statements and notes, as well as management’s discussion and analysis, are available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at http://www.sedar.com and on Bonavista’s website at www.bonavistaenergy.com.
Highlights |
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Three months ended June 30, |
Six months ended June 30, |
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2018 |
2017 |
% Change |
2018 |
2017 |
% Change |
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Financial |
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($ thousands, except per share) |
|||||||||
Production revenues |
121,102 |
140,731 |
(14)% |
259,490 |
283,913 |
(9)% |
|||
Adjusted funds flow(1) |
65,704 |
76,570 |
(14)% |
134,832 |
147,421 |
(9)% |
|||
Per share(1)(2) |
0.25 |
0.30 |
(17)% |
0.52 |
0.58 |
(10)% |
|||
Dividends declared |
2,536 |
2,503 |
1% |
5,059 |
5,006 |
1 % |
|||
Per share |
0.01 |
0.01 |
— % |
0.02 |
0.02 |
— % |
|||
Net income (loss) |
(49,564) |
44,490 |
(211)% |
(51,601) |
132,918 |
(139)% |
|||
Per share(3) |
(0.19) |
0.17 |
(212)% |
(0.20) |
0.52 |
(138)% |
|||
Adjusted net income(4) |
2,524 |
2,729 |
(8)% |
3,680 |
12,663 |
(71)% |
|||
Per share(3) |
0.01 |
0.01 |
— % |
0.01 |
0.05 |
(80)% |
|||
Total assets |
2,889,457 |
3,210,082 |
(10)% |
||||||
Long-term debt, net of working capital |
857,099 |
844,808 |
1% |
||||||
Long-term debt, net of adjusted working capital(5) |
826,552 |
861,784 |
(4)% |
||||||
Shareholders’ equity |
1,490,460 |
1,699,898 |
(12)% |
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Capital expenditures: |
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Exploration and development |
33,148 |
59,820 |
(45)% |
77,003 |
152,094 |
(49)% |
|||
Acquisitions, net of dispositions |
725 |
(290) |
350% |
822 |
(7,830) |
110% |
|||
Weighted average outstanding equivalent shares: (thousands)(3) |
|||||||||
Basic |
258,002 |
254,965 |
1% |
257,489 |
254,784 |
1% |
|||
Diluted |
266,999 |
262,958 |
2% |
266,386 |
262,715 |
1% |
|||
Operating |
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(boe conversion – 6:1 basis) |
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Production: |
|||||||||
Natural gas (mmcf/day) |
301 |
310 |
(3)% |
311 |
302 |
3% |
|||
Natural gas liquids (bbls/day) |
15,950 |
18,364 |
(13)% |
16,214 |
18,625 |
(13)% |
|||
Oil (bbls/day)(6) |
2,091 |
2,288 |
(9)% |
2,209 |
2,423 |
(9)% |
|||
Total oil equivalent (boe/day) |
68,214 |
72,313 |
(6)% |
70,304 |
71,303 |
(1)% |
|||
Product prices:(7) |
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Natural gas ($/mcf) |
2.62 |
3.10 |
(15)% |
2.74 |
3.11 |
(12)% |
|||
Natural gas liquids ($/bbl) |
32.56 |
27.91 |
17% |
32.11 |
27.21 |
18% |
|||
Oil ($/bbl)(6) |
64.15 |
58.91 |
9% |
61.88 |
58.70 |
5% |
|||
Total oil equivalent ($/boe) |
21.16 |
22.24 |
(5)% |
21.48 |
22.26 |
(4)% |
|||
Operating expenses ($/boe) |
5.78 |
5.61 |
3% |
5.71 |
5.54 |
3% |
|||
General and administrative expenses ($/boe) |
0.96 |
0.91 |
5% |
1.03 |
0.95 |
8% |
|||
Cash costs ($/boe)(8) |
9.47 |
8.96 |
6% |
9.42 |
8.97 |
5% |
|||
Operating netback ($/boe)(9) |
12.95 |
14.14 |
(8)% |
13.04 |
13.95 |
(7)% |
NOTES: |
|
(1) |
Management uses adjusted funds flow to analyze operating performance, dividend coverage and leverage. Adjusted funds flow as presented does not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculations of similar measures for other entities. Adjusted funds flow 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 adjusted funds flow throughout this report are based on cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and interest expense. Adjusted funds flow per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income (loss) per share. |
(2) |
Basic adjusted funds flow 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 (net of tax) unrealized gains and losses on financial instrument commodity contracts, unrealized gains and losses on financial instrument contracts and unrealized foreign exchange gains and losses associated with the revaluation of US denominated senior unsecured notes. |
(5) |
Amounts have been adjusted to exclude associated current assets or liabilities from financial instrument commodity contracts and decommissioning liabilities. Also referenced as total net debt. |
(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 interest expense. |
(9) |
Operating netback as presented does not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculations of similar measures for other entities. Operating netback is calculated using production revenues including realized gains and losses on financial instrument commodity contracts less royalties, operating and transportation expenses calculated on a per boe basis. |
Three months ended |
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Share Trading Statistics |
June 30, 2018 |
March 31, 2018 |
December 31, 2017 |
September 30, 2017 |
($ per share, except volume) |
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High |
1.75 |
2.32 |
3.01 |
3.37 |
Low |
1.13 |
1.11 |
1.77 |
2.55 |
Close |
1.49 |
1.18 |
2.25 |
2.98 |
Average Daily Volume – Shares |
1,086,460 |
1,070,659 |
860,422 |
617,169 |
MESSAGE TO SHAREHOLDERS
Enhancing excess adjusted funds flow while maintaining production has been our focus in 2018. In the first six months of this year, we have produced on average 70,304 boe per day while spending only 57% of adjusted funds flow on our exploration and development (E&D) program. This has resulted in $51.5 million of surplus funds, net of dividends, available to allocate to total net debt reduction, realizing 65% of our annual target year-to-date. We remain on track to produce between 69,000 and 71,000 boe per day in 2018 and meaningfully reduce total debt throughout the year.
Significant maintenance on NOVA Gas Transmission Ltd. (NGTL), and an active facility turnaround season led to a modest development program in the second quarter, drilling only six wells and completing one well. Notwithstanding the curtailment of approximately 2,400 boe per day due to these interruptions, production averaged 68,214 boe per day in the quarter.
A second quarter highlight of our E&D program was a significant infrastructure project at Strachan. Completed in June, this project enables the start-up of our five-well liquids-rich development program in the second half of 2018 through a low-cost processing facility. We will remain focused on leveraging our low-cost structure and liquids-rich drilling inventory to enhance adjusted funds flow for the remainder of the year.
Operational and financial accomplishments for the second quarter of 2018 include:
- Generated adjusted funds flow of $65.7 million, which was 18% ahead of budget largely due to stronger natural gas, oil and natural gas liquids (NGL) prices relative to forecast.
- Executed an E&D capital spending program of $33.1 million, equal to 50% of adjusted funds flow, to drill six (5.8 net) wells and complete one well. With one well on production, the remaining five wells drilled will be brought on production late in the third quarter.
- Production averaged 68,214 boe per day for the quarter, which was modestly ahead of our budget. This includes an impact of approximately 3,500 boe per day of curtailed production resulting from facility turnarounds, ethane (C2) rejection at midstream facilities and significant NGTL maintenance. Current production is approximately 68,000 boe per day.
- Allocated $29.0 million of excess adjusted funds flow to debt repayment, reducing long-term debt, net of adjusted working capital, by four percent to $826.6 million relative to the same prior year period.
- Improved NGL benchmark and contracted pricing in Q2 resulted in a 17% improvement in realized pricing relative to the same prior year period.
- Reduced payments to service our long-term debt with interest expense decreasing by 16% relative to the same prior year period.
- Realized cash costs of $9.47 per boe, up six percent over the prior year period, primarily reflecting an increase in transportation costs associated with access to the Dawn market and unutilized NGTL firm transportation service.
- Protected adjusted funds flow through the summer season with our commodity hedge portfolio having 227,000 mcf per day hedged at an AECO price of $2.92 per mcf and 75,000 mcf per day diversified beyond AECO for full protection against daily AECO volatility.
2018 YEAR-TO-DATE CORE AREA HIGHLIGHTS
DEEP BASIN CORE AREA
Our Deep Basin core area is characterized by stacked, resource-rich natural gas reservoirs with low cost and high margin operations. Our production base and development plans are supported by having ownership in approximately 260 mmcf per day of operated process capacity, and adequate firm receipt service on NOVA Gas Transmission Ltd. (“NGTL”) to accommodate all of our budgeted natural gas production for 2018.
During the first half of 2018, we produced approximately 29,416 boe per day in this core area, representing nine percent growth relative to the prior year period despite approximately 900 boe per day being curtailed due to NGTL maintenance in the second quarter. We spent $30.3 million on E&D activities in the first half with all drilling and completing activity having taken place in the first quarter. For the remainder of the year, we will spend approximately $20 million to drill five (4.5 net) wells, with three of the five wells targeting liquids rich natural gas and oil opportunities.
The Deep Basin wells brought on-stream in the first half of 2018 were focused on high rate natural gas development in the Spirit River and Bluesky zones with seven of the nine wells connected to our low-cost Ansell facility. The two Ansell Wilrich extended reach wells continue to demonstrate strong production rates. After 120 days on production these two wells have averaged 6.1 mmcf per day a 26% improvement over our program in the second half of 2017. The remainder of the activity occurred in the Edson area where five wells are connected to our Ansell facility through a recently commissioned compressor station operating at full capacity since March, with one well left to bring on-stream. The remaining two wells have been restricted to 120 day gas rates between five and six mmcf per day through a nearby non-operated processing facility.
WEST CENTRAL CORE AREA
Our West Central core area has a predictable production base with approximately 745,000 net acres and a drilling inventory of approximately 720 horizontal locations within our key plays. This area draws its strength from a low-cost structure, extensive infrastructure and consistent well results.
During the first half of 2018, we spent $43.4 million on E&D activities to drill nine (8.8 net) liquid rich natural gas wells in the Falher, Notikewin and Glauconite formations. At Morningside our northern step-out Falher well has performed above expectations averaging 6 mmcf per day over its first 120 days on production. The Ferrier Notikewin and Willesden Green Glauconite wells drilled in the second quarter will be completed and brought on production late in the third quarter.
At our Strachan Glauconite play, the construction of our compression and pipeline infrastructure to an alternate processing facility has been completed and the majority of our production has been diverted since the end of June. We are currently drilling the fourth well of our five well program and will complete all five wells throughout the second half of the year. This new low-cost processing solution combined with approximately 50 barrels per mmcf of natural gas liquids (weighted 50% to condensate) will result in some of the most economic development wells for Bonavista in 2018. With approximately 100 Strachan Glauconite drilling locations in our prospect inventory, 80% of which are un-booked, this area has significant potential for value appreciation in the current price environment.
For the remainder of the year, nearly 70% of the remaining E&D spending will be allocated to our liquid rich plays in our West Central core area. Approximately $46 million will be spent to drill nine (9.0 net) wells in our most economic plays at Strachan and Morningside.
OUTLOOK
Notwithstanding the continued volatility we are experiencing with western Canadian natural gas prices, the broader supply and demand fundamentals have become more constructive. A warmer than expected shoulder season coupled with above average temperatures this summer across much of North America has resulted in stronger than anticipated demand for natural gas.
Specific to the U.S., natural gas demand continues to exhibit structural growth characteristics. Significant demand for cooling has caused power demand in the U.S. to track near record highs, approaching 40 bcf per day recently and average 26.7 bcf per day year-to-date, a 10% increase relative to the same period last year. Natural gas export volumes remain strong, with export volumes via pipeline to Mexico growing 12% year over year in June to average 4.5 bcf per day and recently growing above 5 bcf per day in the first two weeks of July.
Lastly, liquefied natural gas (“LNG”) exports are expected to remain in excess of 3 bcf per day for the remainder of this year with the total liquefaction capacity of the U.S. scheduled to multiply three-fold to approximately 9 bcf per day within the next 24 to 30 months. Collectively, and despite record natural gas supply, these events have moderated the natural gas storage inventory in the U.S. whereby storage levels are currently 24% below last year’s levels. Fortunately, this demand for natural gas in the U.S. has also elevated the call for natural gas volumes from Canada to 5.5 bcf per day year-to-date, an eight percent increase above last year’s levels over the same period.
In Canada, natural gas demand has been robust year-to-date, supported by weather, continued growth in oilsands consumption and the accelerated decommissioning of coal-fired electricity generation. Remarkably, natural gas consumption to generate electricity in Alberta is scheduled to grow 40% to 800 mmcf per day in 2018 relative to 2017. These events, along with curtailed access to storage in Alberta, has created a 24% deficit to Canadian storage levels relative to last year. With over half of the injection season behind us, this should support western Canadian natural gas pricing into the winter heating season.
Longer term, optimism is building with LNG export potential, specifically LNG Canada located on the west coast of Canada. Provincial tax incentives, service contracts announcements, hiring showcases and onsite activity all point to a constructive final investment decision (FID) announcement early this fall. It is becoming much clearer that Canada can compete in the global LNG market at a time when the market is poised to absorb new supply. A positive FID announcement with LNG Canada will act as a catalyst to grow LNG export capacity in Canada beyond this project creating incremental long-term natural gas demand.
We believe Bonavista remains well positioned to create long-term value for our shareholders in light of these constructive natural gas fundamentals. Having said that, we will remain disciplined with what we control in the current low-margin price environment as we prepare to adapt to the changing fundamentals.
We will be allocating the majority of our remaining E&D spending this year to opportunities rich in NGLs designed to maximize netback while we maintain production levels and generate excess funds flow. In support of the capital program, we continue to enhance the quality of our asset portfolio through strategic asset swaps and acquisitions and the application of technology. Our full year capital program remains on target between $135 and $155 million, generating an annual production forecast of between 69,000 and 71,000 boe per day and excess adjusted funds flow between $70 and $90 million.
We thank our employees for their commitment and dedication and our shareholders for their on-going support. We look forward to creating additional financial flexibility throughout the remainder of 2018.