Bonterra Energy Corp. Announces First Quarter 2019 Financial and Operational Results

Source Press Release
Company Bonterra Energy Corp. 
Tags Strategy - Corporate, Financial & Operating Data
Date May 06, 2019

Bonterra Energy Corp. () (TSX: BNE) ("Bonterra" or the "Company") is pleased to announce its operating and financial results as at and for the three months ended March 31, 2019.  The related unaudited condensed financial statements and notes, as well as management's discussion and analysis ("MD&A"), are available on SEDAR at  and on Bonterra's website at  . 

HIGHLIGHTS

As at and for the three months ended  March 31,
  2019 
December 31,
 2018 
March 31, 
2018 
($000s except $ per share) 
FINANCIAL       
Revenue - realized oil and gas sales  49,834  34,988  57,124 
Funds flow (1)  24,363  10,618  27,959 
Per share - basic and diluted  0.73  0.32  0.84 
Dividend payout ratio  4%  66%  36% 
Cash flow from operations  15,123  20,509  29,877 
Per share - basic and diluted  0.45  0.61  0.90 
Dividend payout ratio  7%  34%  33% 
Cash dividends per share  0.03  0.21  0.30 
Net earnings (loss)  1,457  (10,909)  3,395 
Per share - basic and diluted  0.04  (0.33)  0.10 
Capital expenditures  21,062  4,785  36,168 
Total assets  1,124,043  1,103,833  1,142,670 
Working capital deficiency  30,139  30,281  46,630 
Long-term debt  296,594  298,660  291,994 
Shareholders' equity  484,980  483,970  504,240 
OPERATIONS       
Oil  -bbl per day  7,081  7,756  8,034 
  -average price ($ per bbl)  64.87  38.96  67.78 
NGLs  -bbl per day  949  1,025  900 
  -average price ($ per bbl)  31.40  34.73  38.70 
Natural gas  -MCF per day  23,938  24,045  24,701 
  -average price ($ per MCF)  2.70  1.77  2.24 
Total barrels of oil equivalent per day (BOE)(2)  12,020  12,789  13,051 

   
(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. 

During the first quarter of 2019, Bonterra continued to focus on the development of its high-quality, light oil-weighted, Pembina Cardium assets in Alberta. Through the period, the Company benefitted from higher realized oil prices due to a more favourable Canadian oil price differential environment supporting stronger funds flow compared to the previous quarter.  Bonterra drilled 12 gross (10.8 net) Cardium wells, completed 10 gross (9.1 net) wells and tied-in and placed on production seven gross (6.1 net) wells, with the remaining five wells placed on production in April 2019. Production averaged 12,020 BOE per day for Q1 2019, reflecting the impact of extreme cold weather conditions on operations in February resulting in freeze-offs and the timing of new wells that were drilled and completed in the first quarter.  The full impact of Bonterra's first quarter drilling program will be realized in the second quarter, as productionvolumes for the month of April averaged approximately 13,200 BOE per day, 10 percent higher than the Q1 2019 average.

Q1 2019 Highlights

  • Achieved average quarterly production of 12,020 BOE per day, eight percent lower than Q1 2018 volumes of 13,051 BOE per day due to weather-related delays and wells coming on production after quarter end. 

  • Generated funds flow of $24.4 million ($0.73 per share) a 129 percent increase over the $10.6 million ($0.32 per share) in Q4 2018 largely due to significantly improved oil price differentials, but lower than Q1 2018 funds flow of $28.0 million ($0.84 per share).  

  • Derived 88 percent of Q1 2019 revenue from oil and NGLs, realizing an average Canadian realized price for crude oil of $64.87 per bbl and $31.40 per bbl for NGLs.

  • Invested $19.4 million in net capital expenditures to drill 12 gross (10.8 net) Cardium wells, complete 10 gross (9.1 net) wells and tie-in and place on production seven gross (6.1 net) Cardium wells.  In addition, the Company invested $1.7 million on related infrastructure costs, recompletions and other capital expenditures.

  • Relative to production from the fourth quarter of 2018 which averaged 12,789 BOE per day, the Company's first quarter 2019volumes were lower due to the timing of new wells coming on production and 560 BOE per day of shut-in production. Shut-in production was the result of extremely cold weather through most of February, a third-party downstream pipeline failure and pressure issues from new wells backing out existing wells.  Of the 11 gross (10.7 net) operated wells drilled in the first quarter, three came on production in February and three came on production in mid-March, with the remaining five wells on production in April 2019.  The Company also drilled and completed one gross (0.1 net) non-operated well which came on production in Q1 2019.

  • Bonterra's commitment to delivering strong operational execution continued through the first quarter, demonstrated by the following:


    • Stronger cash netbacks averaging $22.53 per BOE compared to $8.07 per BOE in Q4 2018, and five percent below Q1 2018 cash netbacks of $23.81 per BOE; 

    • All-in costs (including royalties, operating costs, general and administrative and interest) were five percent lower at $23.54 per BOE in Q1 2019 compared to $24.82 per BOE in Q1 2018;

    • Q1 2019 production costs on a per unit basis of $14.85 per BOE increased from $14.23 per BOE in Q4 2018 and increased slightly compared to $14.49 per BOE in Q1 2018.  Overall spending on production costs in Q1 2019 declined relative to Q4 2018 and Q1 2018, however, did increase on a per unit basis driven by shut-in production and the deferred benefit from new productionresulting in slightly lower production volumes in the quarter; and 

    • Realized an average crude oil price of C$64.87 per bbl and an average overall price of C$46.07 per BOE in Q1 2019. 

  • Paid out $0.03 per share in cash dividends to shareholders in the first quarter, resulting in a payout ratio of four percent of funds flow.

  • Reduced net debt to $326.7 million as at March 31, 2019, a reduction of $2.2 million compared to $328.9 million at December 31, 2018, a meaningful achievement given the first quarter historically has the highest capital spending of all periods during the year.

To date in the first quarter of 2019, Alberta's mandated curtailment has contributed to a narrowing of Canadian light, sweet crude oil differentials back to normalized ranges and the improved prices positively supported Bonterra's realized oil prices in the first quarter.  The Company will continue to regularly monitor commodity price changes and funds flow with the primary objective of reducing debt and as appropriate, adjusting capitalexpenditures and dividend levels. 

Subsequent to the end of the quarter, the Company's syndicate of Canadian financial institutions have agreed to extend the borrowing base redetermination date until May 31, 2019. At March 31, 2019 the Company had $296.6 million drawn of the Company's $380.0 million syndicated credit facility.

Outlook

Bonterra's original 2019 capital budget of $57 to $77 million remains unchanged and is intended to maintain a balance between funds flow and capital spending with excess cash being directed to strengthen the balance sheet.  Annual production volumes in 2019 are forecast to be in the range of 12,600 to 13,200 BOE per day, of which approximately 62 percent would be sweet crude oil, with a forecast exit rate between 13,000 and 14,000 BOE per day, positioning Bonterra well for a strong start to 2020.  

In order to protect funds flow, the Company has layered on 2,000 bbls per day of various physical oil delivery sales contracts through the end of September, 2019 at various Canadian realized oil pricing ranging from C$72.99 to C$77.35 per bbl and will continue to evaluate opportunities to secure prices for both WTI and light sweet oil differentials. 

The Company intends to remain focused on financial discipline and cost control, including taking steps to further reduce debt levels relative to peers and strengthening the balance sheet.  With one of the lowest annual production decline rates and one of the largest inventory of economic undrilled locations, the Company is well positioned to continue returning capital to shareholders in the form of dividends while focusing on measured per share growth in cash flow, production and reserves.

Annual General Meeting

Bonterra will be holding its annual meeting of shareholders on Wednesday, May 15, 2019, at 10:00 a.m. (Calgary time) in the Bow Glacier Room/Bow River Room at Centennial Place West Tower, Third Floor, 250 - 5th Street S.W., Calgary, Alberta.  All shareholders and other interested parties are invited to attend. Details of the agenda are included in the Company's Management Information Circular filed on SEDAR.

Bonterra Energy Corp. is a conventional oil and gas corporation with operations in Alberta, Saskatchewan and British Columbia. The Company's shares are listed on The Toronto Stock Exchange under the symbol "BNE".

Cautionary Statements

This 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  

Use of Non-IFRS Financial Measures

Throughout 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 Information

Certain 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.

Drilling Locations

This press release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations, which are sometimes collectively referred to as "booked locations", are derived from the independent reserves evaluation prepared by Sproule Associates Ltd. as of December 31, 2018 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on Bonterra's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves. Of the 1,051 Gross Cardium drilling locations identified herein, 371 are proved locations, 7 are probable locations and 680+ are unbooked locations.  Unbooked locations have been identified by management as an estimation based on industry practice and internal review of our multi-year drilling activities, which include an evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Bonterra will drill all unbooked drilling locations and, if drilled, there is no certainty that such locations will result in additional oil and gas reserves or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drillingexisting wells in relative close proximity to such unbooked drillinglocations, some of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and, if drilled, there is more uncertainty that such wells will result in additional oil and gas reserves or production.  No locations have been assigned resources other than reserves ("ROTR").  All drilling counts cited herein are net.  

Frequently recurring terms

Bonterra 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.

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd