BNE Bonterra Energy Corp

Bonterra Energy Corp. (www.bonterraenergy.com) (TSX: BNE) (“Bonterra” or the “Company”) is pleased to announce its operating and financial results as at and for the three and nine months ended September 30, 2018.  The related unaudited condensed financial statements and notes, as well as management’s discussion and analysis (“MD&A”), are available on SEDAR at www.sedar.com and on Bonterra’s website at www.bonterraenergy.com. 

HIGHLIGHTS

		Three months ended				Nine months ended
As at and for the periods ended ($ 000s except for $ per share and $ per BOE)		September 30,  2018		September 30, 2017		September 30,  2018		September 30, 2017
FINANCIAL
Revenue - realized oil and gas sales		63,817		46,349		188,400		148,374
Funds flow (1)		31,032		21,745		96,633		75,496
Per share - basic and diluted		0.93		0.65		2.90		2.27
Dividend payout ratio		32	%	46	%	31	%	40	%
Cash flow from operations		33,669		25,491		95,454		77,401
Per share - basic and diluted		1.01		0.77		2.87		2.32
Dividend payout ratio		30	%	40	%	31	%	39	%
Cash dividends per share		0.30		0.30		0.90		0.90
Net earnings (loss)		5,756		(3,043	)	18,076		410
Per share - basic and diluted		0.17		(0.09	)	0.54		0.01
Capital expenditures, net of dispositions		18,814		14,121		73,952		63,666
Total assets						1,137,748		1,146,498
Working capital deficiency						35,319		28,260
Long-term debt						293,197		345,322
Shareholders' equity						500,507		517,719
OPERATIONS
Oil	-barrels per day	7,949		8,038		8,242		7,954
	-average price ($ per barrel)	77.20		53.48		73.93		57.38
NGLs	-barrels per day	1,070		1,000		985		886
	-average price ($ per barrel)	43.95		27.81		42.28		28.67
Natural gas	-MCF per day	24,144		25,460		24,719		23,959
	-average price ($ per MCF)	1.37		1.81		1.58		2.58
Total barrels of oil equivalent per day (BOE) (2)		13,043		13,281		13,347		12,834

(1) Funds flow is not a recognized measure under IFRS.  For these purposes, the Company defines funds flow as funds provided by operations including proceeds from sale of investments and investment income received excluding the effects of changes in non-cash working capital items and decommissioning expenditures settled.

(2) BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Throughout the third quarter of 2018, Bonterra continued to focus on the development of its high-quality, light oil weighted assets that are concentrated in Alberta’s Pembina Cardium area, resulting in average production of 13,043 BOE per day.  Supported by strong oil and natural gas liquids (“NGLs”) pricing during the quarter, Bonterra generated quarterly funds flow of $31.0 million ($0.93 per share).  Through the first nine months of 2018, the Company has benefited from a strengthening crude oil price environment and increased production year to date, which has resulted in funds flow that has enabled Bonterra to maintain its dividend and invest capital into its attractive, oil-weighted asset base.

Q3 2018 Highlights

• Funds flow of $31.0 million in Q3 2018, or $0.93 per share was 43 percent higher than $21.7 million in Q3 2017, or $0.65 per share;
• Cash dividends to shareholders totaled $0.30 per share in the third quarter, representing a dividend payout ratio of 32 percent of funds flow;
• Averaged 13,043 BOE per day of production in Q3 2018, approximately two percent lower than 13,281 BOE per day in Q3 2017, and six percent lower than Q2 2018, reflecting the impact of facility turnarounds and fewer new production volumes coming on line in Q3 2018 relative to Q2 2018.  Production volumes averaged 13,347 BOE per day for the first nine months of 2018, which was a 4 percent increase compared to the first nine months of 2017;
• Cash netbacks in Q3 2018 of $26.31 per BOE were 50 percent higher than the $17.59 per BOE generated in Q3 2017.  Cash netbacks for the first nine months of 2018 were $26.83 per BOE, a 25 percent increase over $21.48 per BOE for the same period in 2017;
• Realized an average crude oil price in Q3 2018 of $77.20 per bbl and an average overall realized price of $53.18 per BOE, representing increases of 44 and 40 percent, respectively, compared to Q3 2017;
• Invested approximately $74 million in capital expenditures during the first nine months of 2018, representing the majority of the Company’s $75 million capital program for the year, which is largely due to $36.2 million of capital spent in Q1 2018 to bring volumes on stream prior to spring break-up;
• Drilled 27 gross (26.8 net) wells during the first nine months of 2018, of which 24 gross (23.9 net) wells were completed, equipped, tied-in and placed on production with the remaining three wells brought on production in October 2018.  In addition, five gross (0.8 net) non-operated wells were drilled, completed, equipped and brought on production through the first three quarters of 2018;
• Production costs averaged $16.31 per BOE in Q3 2018 compared to $13.01 per BOE in Q2 2018 and averaged $14.58 per BOE for the first nine months of the year, reflecting additional third quarter costs associated with seasonal lease, well and facility maintenance programs and the impact of lower volumes on higher costs;
• Net debt was successfully reduced during the period, ending Q3 2018 at $328.5 million, approximately $2.0 million lower than Q2 2018, but approximately $8.5 million higher than year end 2017 due to the heavily weighted capital program in Q1 2018; and
• Net earnings of $5.8 million in Q3 2018 compared to a net loss of $3.0 million for Q3 2017 and net earnings of $18 million for the first nine-months of 2018 compared to $0.4 million in the same period of 2017.

The Company posted a successful quarter financially and operationally despite facing seasonal maintenance and major facility turnarounds, generally required every five years, which curtailed production volumes by approximately 500 BOE per day and added to production costs on a per BOE basis.  The impact to production volumes was partially offset by stronger crude oil prices which contributed to Bonterra’s ability to generate funds flow that exceeded capital spending and sustain its $0.10 per share monthly dividend.  Capital invested year to date reflects a heavily weighted capital program during the first five months of 2018 which enabled Bonterra to take advantage of favourable drilling conditions and strong realized pricing.  Approximately $61.9 million was spent to drill 27 gross operated (26.8 net) wells and complete, equip and tie-in 24 gross (23.8 net) wells.  The remaining $11.9 million was spent on infrastructure and non-operated wells.  The Company anticipates annual capital spending for the year to be approximately $80 million, which will allow the Company to drill two gross (2.0 net) wells in December that will add production early in 2019 and also complete, equip and tie-in three gross (3.0 net) wells previously drilled in the third quarter.

During the nine months of 2018, production costs on a per BOE basis increased to $14.58 per BOE from $12.74 per BOE for the same period in 2017. In the fourth quarter, the Company expects power costs to remain high, offset by lower maintenance costs and fewer facility turnarounds, resulting in lower production costs per BOE in Q4 2018 compared to Q3 2018. The Company anticipates annual production costs to range $14.00 to $14.50 per BOE for 2018.

Approximately 94 percent of the Company’s revenue is weighted towards higher value crude oil and NGLs which supported field netbacks in the third quarter of $30.70 per BOE, up from $22.80 per BOE in Q3 2017, and cash netbacks of $26.31 per BOE compared to $17.59 per BOE in the same quarter in 2017. 

Q4 and 2018 Outlook

The Company will continue to focus on shareholder value creation by remaining financially disciplined in its efforts to reduce debt, pursue further operational efficiencies and manage its stable monthly dividend.    

Given the Company’s performance year-to-date, Bonterra remains on target to meet annual production guidance of 13,200 to 13,500 BOE per day.  The Company exited Q3 2018 with a net debt to Q3 2018 annualized cash flow from operations ratio of 2.4 times, which is currently in-line with the guided range of 2.1 to 2.5 times at year end 2018.  

The Company anticipates lower field net backs and cash flow in the fourth quarter compared to Q3 2018 and therefore a negative effect to the annualized net debt to cash flow from operations ratio for the year ended 2018. A shortage of pipeline capacity and recent refinery maintenance has led to material apportionment and price weakness for Canadian light oil, making Canadian oil much cheaper relative to the US benchmark. Light oil has been trading at discounts up to US$30 per barrel in Q4 compared to a differential of approximately US$6 to US$7 per barrel in Q3.

Bonterra offers investors a conservative and consistent operational approach, which has proven successful across a variety of commodity price cycles.  This approach, combined with a production decline rate of approximately 22 percent, significant exposure to the Alberta Pembina Cardium pool, and a sizeable inventory of low-risk, highly economic undrilled locations, is expected to continue supporting the Company’s operations over time.   

Bonterra Energy Corp. is a conventional oil and gas corporation with operations in Alberta, Saskatchewan and British Columbia, focused on its long-term model of generating sustainable growth plus a dividend. The Company’s shares are listed on The Toronto Stock Exchange under the symbol "BNE".

For further information please contact:George F. Fink, Chairman and CEO Robb D. Thompson, CFO Adrian Neumann, COOTelephone: (403) 262-5307Fax: (403) 265-7488Email: info@bonterraenergy.com

Cautionary StatementsThis summarized news release should not be considered a suitable source of information for readers who are unfamiliar with Bonterra Energy Corp. and should not be considered in any way as a substitute for reading the full report.  For the full report, please go to www.bonterraenergy.com

Use of Non-IFRS Financial MeasuresThroughout this release the Company uses the terms "payout ratio" and "cash netback" to analyze operating performance, which are not standardized measures recognized under IFRS and do not have a standardized meaning prescribed by IFRS. These measures are commonly utilized in the oil and gas industry and are considered informative by management, shareholders and analysts. These measures may differ from those made by other companies and accordingly may not be comparable to such measures as reported by other companies.

The Company calculates payout ratio by dividing cash dividends paid to shareholders by cash flow from operating activities, both of which are measures prescribed by IFRS which appear on our statements of cash flows. We calculate cash netback by dividing various financial statement items as determined by IFRS by total production for the period on a barrel of oil equivalent basis.

Forward Looking InformationCertain statements contained in this release include statements which contain words such as "anticipate", "could", "should", "expect", "seek", "may", "intend", "likely", "will", "believe" and similar expressions, relating to matters that are not historical facts, and such statements of our beliefs, intentions and expectations about development, results and events which will or may occur in the future, constitute "forward-looking information" within the meaning of applicable Canadian securities legislation and are based on certain assumptions and analysis made by us derived from our experience and perceptions. Forward-looking information in this release includes, but is not limited to: expected cash provided by continuing operations; cash dividends; future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and other development trends of the oil and gas industry; business strategy and outlook; expansion and growth of our business and operations; and maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies; credit risks; and other such matters.

All such forward-looking information is based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. The risks, uncertainties, and assumptions are difficult to predict and may affect operations, and may include, without limitation: foreign exchange fluctuations; equipment and labour shortages and inflationary costs; general economic conditions; industry conditions; changes in applicable environmental, taxation and other laws and regulations as well as how such laws and regulations are interpreted and enforced; the ability of oil and natural gas companies to raise capital; the effect of weather conditions on operations and facilities; the existence of operating risks; volatility of oil and natural gas prices; oil and gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; stock market volatility; opportunities available to or pursued by us; and other factors, many of which are beyond our control.

Actual results, performance or achievements could differ materially from those expressed in, or implied by, this forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do, what benefits will be derived there from. Except as required by law, Bonterra disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.

The forward-looking information contained herein is expressly qualified by this cautionary statement.

Frequently recurring termsBonterra uses the following frequently recurring terms in this press release: “WTI” refers to West Texas Intermediate, a grade of light sweet crude oil used as benchmark pricing in the United States; “MSW Stream Index” or “Edmonton Par” refers to the mixed sweet blend that is the benchmark price for conventionally produced light sweet crude oil in Western Canada; “AECO” refers to Alberta Energy Company, a grade or heating content of natural gas used as benchmark pricing in Alberta, Canada; “bbl” refers to barrel; “NGL” refers to Natural gas liquids; “MCF” refers to thousand cubic feet; “MMBTU” refers to million British Thermal Units; “GJ” refers to gigajoule; and “BOE” refers to barrels of oil equivalent.  Disclosure provided herein in respect of a BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Numerical AmountsThe reporting and the functional currency of the Company is the Canadian dollar.

The TSX does not accept responsibility for the accuracy of this release.