BlackPearl Announces First Quarter 2015 Financial and Operating Results

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BlackPearl Announces First Quarter 2015 Financial and Operating Results

by ahnationtalk on May 7, 2015575 Views

Press Releases

CALGARY, ALBERTA–( May 6, 2015) – BlackPearl Resources Inc. (“BlackPearl” or the “Company”) (TSX:PXX)(OMX:PXXS) is pleased to announce its financial and operating results for the three months ended March 31, 2015.

Highlights include:

  • Construction of the 6,000 barrels per day first phase of the Onion Lake thermal project is complete and commissioning of the facilities has begun, the project was ahead of schedule and within budget;
  • At Blackrod, the pilot results from the second SAGD well pair continue to be positive, the well is currently producing in excess of 500 barrels of oil per day with a steam oil ratio of under 3;
  • Despite low oil prices which resulted in a 63% decrease in revenues to $22.1 million, funds flow from operations was $13 million;
  • Production averaged 8,269 barrels of oil equivalent (boe) per day, a 12% decrease compared to Q1 2014 volumes – the lower production volumes reflect, in part, the Company’s decision to shut-in 40 wells during a period of extremely low oil prices.

John Festival, President of BlackPearl commented “Low crude oil prices made for a challenging Q1 for BlackPearl and most of industry. However, Q1 was a very exciting period for us. We recently completed construction of the first phase of the Onion Lake thermal project and we have started commissioning the facilities. The project was completed ahead of schedule and capital costs were right in line with our budget of $223 million. We are looking forward to commencing steam injection in the wells later this month and initial oil production should begin three to six months after that. This is an important milestone for BlackPearl. Our first thermal project has been completed successfully and it is the largest project the Company has undertaken. Production from the Onion Lake thermal project should be some of our lowest cost production, which is critical in this lower oil price environment”.

Property Review

Onion Lake

In 2015, we achieved some important milestones with the Onion Lake thermal project. Construction of the first phase of the thermal project was completed in April and we started commissioning various components of the central processing facilities, well pads and source water facilities. Commissioning is expected to take four to eight weeks. We are planning to begin steam injection to the first well pad (seven wells) by the end of May. First oil production is expected approximately three to six months after we start steam injection. Oil production ramp-up to design capacity of 6,000 barrels per day is expected to take 12 to 18 months after initial steam injection.

This phase of the project includes 13 horizontal production wells on two well pad sites. All of these wells were drilled in late 2014 and were completed during the first quarter of 2015. In addition, we have 35 vertical steam injection wells which were completed during the first quarter. The steam generation facilities are designed to generate approximately 17,000 barrels of steam per day. Final capital costs for this phase of the project are estimated to be between $220 and $225 million, which is in line with our original budget estimates. No new conventional drilling occurred during the first quarter of 2015 due to low oil prices. In addition, after an extensive well by well review of our operations we shut-in 40 producing wells at Onion Lake during the first quarter. These wells were some of the higher cost wells to operate in the field and were not economic at current oil prices. These 40 wells were cumulatively producing approximately 1,000 barrels of oil per day before they were shut-in. We plan to bring these wells back on production as oil prices improve.


We continue to achieve encouraging results from the second pilot well pair at Blackrod. Technical analysis indicated that the steam chamber was continuing to build and that the well was still in its production ramp-up phase. In order to optimize well performance a planned well intervention was scheduled for February which impacted production rates in the first quarter. The well was put back on production in March and in April produced in excess of 500 barrels of oil per day at a steam oil ratio of 2.6, and is continuing to ramp up. Cumulatively, the well has produced in excess of 115,000 barrels of oil.

We continue to advance our regulatory application for an 80,000 barrel per day commercial development project at Blackrod. The Alberta Energy Regulator (“AER”) is continuing with their final review of the application. We have not received any additional supplemental requests for information from the AER. During this time we have continued consultations with First Nations and other stakeholders in the area to ensure their concerns have been addressed. It is expected that final approval of the application will be obtained in the next few months.


No new activities were initiated at Mooney during the first quarter due to low oil prices. Expansion of the ASP flood to the phase two lands has been deferred until oil prices improve. Our focus during the first quarter was to review operations and flood development. As a result of this review, we were able to significantly reduce operating costs at Mooney, primarily by optimizing the amount of chemical injection in certain areas of the reservoir due to the maturity of the flood in those areas.


Oil and gas production averaged 8,269 barrels of oil equivalent per day in the first quarter of 2015, a 12% decrease compared with the first quarter of 2014. The decrease in oil production in the first quarter of 2015 is attributable to a number of factors. Due to low oil prices we did not undertake any new drilling activities during the quarter. No new drilling combined with natural production declines at Onion Lake and Mooney resulted in an overall drop in production from these areas. In addition, 40 producing wells in the Onion Lake area were shut-in during the quarter due to low oil prices. In many instances, these were wells with high operating costs that required well servicing and we chose to shut them in rather than incur the expenses to bring them back on production. At the time these wells were shut-in they were producing approximately 1,000 barrels of oil per day. We plan to put these wells back on production when oil prices recover to a level that they can contribute positive cash flow to our operations. Finally, at Blackrod, we shut-in the second pilot well pair for part of the quarter to complete a workover on the well which resulted in lower average production from the area during the quarter.

Average Daily Sales Volume

Production by area (boe/d) Q1 2015 Q4 2014 Q1 2014
Onion Lake 3,959 4,651 4,274
Mooney 2,797 3,236 3,696
John Lake 1,011 1,109 1,069
Other 96 120 113
Blackrod 406 523 211
8,269 9,639 9,363

Financial Results

Oil and gas revenues decreased 63% in the first quarter of 2015 to $22.1 million compared with $59.6 million in Q1 2014. The decrease in revenues is attributable to a 57% decrease in our average sales price and a 12% decrease in production volumes. Our realized oil price (before the effects of risk management activities) in Q1 2015 was $32.05 per barrel compared to $73.23 per barrel in 2014. The decrease in our realized wellhead price reflects significantly lower WTI reference oil prices in Q1 2015 compared with Q1 2014 (US$48.63/bbl vs US$98.68/bbl), partially offset by tighter heavy oil differentials (US$14.71/bbl vs US$23.11/bbl) and a weaker Canadian dollar relative to the US dollar ($0.806 vs $0.906).

Our oil hedging program has helped mitigate some of the negative impact of the low oil price environment in 2015. During the first quarter we realized a gain of $13.7 million from our oil hedging program, which was the equivalent of adding $19.37 per barrel to our wellhead price in the quarter. The following summarizes the hedging contracts we currently have outstanding:

Subject of Contract Volume Term Reference Strike Price Option Traded
Oil 2,500 bbls/d April 1, 2015 to June 30, 2015 CDN$ WCS CDN$ 80.00/bbl Swap
Oil 1,000 bbls/d July 1, 2015 to December 31, 2015 CDN$ WCS CDN$ 64.45/bbl Swap
Oil 1,000 bbls/d July 1, 2015 to December 31, 2015 CDN$ WCS CDN$ 61.00/bbl Swap
Oil 1,000 bbls/d July 1, 2015 to December 31, 2015 CDN$ WCS CDN$ 62.25/bbl Swap
Oil 1,000 bbls/d July 1, 2015 to December 31, 2015 CDN$ WCS CDN$ 72.00/bbl Swap
Oil 1,000 bbls/d January 1, 2016 to December 31, 2016 CDN$ WTI CDN$ 80.00/bbl Sold Call Swaption(1)
Oil 1,000 bbls/d January 1, 2016 to December 31, 2016 USD$ WTI USD$ 65.00/bbl Sold Call Swaption(1)
Oil 1,000 bbls/d January 1, 2016 to December 31, 2016 USD$ WTI USD$ 65.00/bbl Sold Call
Oil 1,000 bbls/d January 1, 2016 to December 31, 2016 USD$ WTI USD$ 65.00/bbl Sold Call
(1) The Company sold a European call option to a counterparty whereby the counterparty can elect on December 31, 2015 to exercise the option to enter into the oil swap.

Operating costs decreased 19% in the first quarter of 2015 to $15.9 million from $19.7 million in the same period in 2014. On a per boe basis, production costs were $22.48 per boe in Q1 2015, a decrease from $23.88 per boe in Q1 2014. The decrease in production expenses in 2015 is attributable, in part, to decreased production volumes. In addition, due to the current low oil price environment the Company has been focusing on reducing production costs. This included negotiating lower service rates with certain suppliers and contractors, deferring well servicing work and shutting-in specific wells that are not economic at current oil prices.

The significantly reduced revenue, partially offset by lower royalties, transportation costs and operating costs resulted in a 44% decrease in funds flow from operations in Q1 2015 to $12.9 million compared to $23.0 million for the same period in 2014.

Financial and Operating Highlights

Three months ended
March 31
2015 2014
Daily production / sales volumes(1)
Oil (bbl/d) 7,885 9,122
Natural gas (mcf/d) 2,303 1,448
Combined (boe/d) 8,269 9,363
Product pricing ($) (before the effects of hedging transactions)
Crude oil – per bbl 32.05 73.23
Natural gas – per mcf 2.63 5.41
Combined – per boe 31.25 72.30
($000’s, except per share and boe amounts)
Oil and gas revenue – gross 22,115 59,555
Gain (loss) on risk management contracts:
Risk management contracts – realized 13,708 (666)
Risk management contracts – unrealized (11,374) (5,301)
2,334 (5,967)
Royalties ($/boe) 5.78 14.00
Transportation costs ($/boe) 1.10 1.87
Operating costs ($/boe) 22.48 23.88
Loss for the period (10,944) (1,126)
Per share, basic and diluted (0.03) (0.00)
Funds flow from operations(2) 12,940 23,037
Capital expenditures 42,981 49,360
Working capital, end of period (11,137) 28,192
Long term debt 78,000
Shares outstanding, end of period 335,638,226 328,398,308
(1) Boe amounts are based on a conversion ratio of 6 mcf of gas to 1 barrel of oil. Boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(2)Funds flow from operations is a non-GAAP measure that represents cash flow from operating activities before decommissioning costs incurred and changes in non-cash working capital related to operations. Funds flow from operations does not have a standardized meaning prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies.

The 2015 first quarter report to shareholders, including the financial statements, management’s discussion and analysis and notes to the financial statements are available on the Company’s website ( or SEDAR (

This news release includes terms commonly used in the oil and natural gas industry, such as funds flow and funds flow from operations which represent cash flow from operating activities expressed before decommissioning costs incurred and changes in non-cash working capital. These terms are used by the Company to analyze operating performance, leverage and liquidity and to provide shareholders and investors with additional information to measure the Company’s performance and efficiency and its ability to fund a portion of its future activities and to service any long-term debt if incurred in the future. These terms do not have standardized meanings prescribed by GAAP and therefore may not be comparable with the calculation of similar measures by other entities. Consequently, these are referred to as non-GAAP measures.


This release contains certain forward-looking statements and forward-looking information (collectively referred to as “forward-looking statements”) within the meaning of applicable Canadian securities laws. All statements other than statements of historic fact are forward-looking statements. Forward-looking statements are typically identified by such words as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” or similar words suggesting future events or future performance.

In particular, but without limiting the foregoing, this report contains forward-looking statements pertaining to our business plans and strategies; capital expenditure and drilling programs including the target date of the end of May for first steam injection at the Onion Lake EOR project and anticipated timing of initial oil production three to four months after steam injection at the Onion Lake EOR project, anticipated final capital costs of between $220 and $225 million for the first phase of the Onion Lake EOR project, reaching peak production rates 12 to 18 months after steam injection at Onion Lake, timing as to when we would bring back on production the Onion Lake wells that were shut-in due to low oil prices and expected timing to receive regulatory approval for our commercial development application at Blackrod.

The forward-looking statements in this document reflect certain assumptions and expectations by management. The key assumptions that have been made in connection with these forward-looking statements include the continuation of current or, where applicable, assumed industry conditions, the continuation of existing tax, royalty and regulatory regimes, commodity price and cost assumptions, the continued availability of cash flow or financing on acceptable terms to fund the Company’s capital programs, the accuracy of the estimate of the Company’s reserves and resource volumes and that BlackPearl will conduct its operations in a manner consistent with past operations. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties which could cause actual results to differ materially from those contained in forward-looking statements. These factors include, but are not limited to, risks associated with fluctuations in market prices for crude oil, natural gas and diluent; risks related to the exploration, development and production of crude oil, natural gas and NGLs reserves; general economic, market and business conditions; substantial capital requirements; uncertainties inherent in estimating quantities of reserves and resources; extent of, and cost of compliance with, government laws and regulations and the effect of changes in such laws and regulations from time to time; the need to obtain regulatory approvals on projects before development commences; environmental risks and hazards and the cost of compliance with environmental regulations; aboriginal claims; inherent risks and hazards with operations such as fire, explosion, blowouts, mechanical or pipe failure, cratering, oil spills, vandalism and other dangerous conditions; potential cost overruns; variations in foreign exchange rates; diluent supply shortages; competition for capital, equipment, new leases, pipeline capacity and skilled personnel; uncertainties inherent in the SAGD bitumen and ASP recovery processes; credit risks associated with counterparties; the failure of the Company or the holder of licenses, leases and permits to meet requirements of such licenses, leases and permits; reliance on third parties for pipelines and other infrastructure; changes in royalty regimes; failure to accurately estimate abandonment and reclamation costs; inaccurate estimates and assumptions by management; effectiveness of internal controls; the potential lack of available drilling equipment and other restrictions; failure to obtain or keep key personnel; title deficiencies with the Company’s assets; geo-political risks; risks that the Company does not have adequate insurance coverage; risk of litigation and risks arising from future acquisition activities. Further information regarding these risk factors and others may be found under “Risk Factors” in the Annual Information Form.

Undue reliance should not be placed on these forward-looking statements. Readers are cautioned that the actual results achieved will vary from the information provided herein and the variations could be material. Readers are also cautioned that the foregoing list of assumptions, risks and factors is not exhaustive. Consequently, there is no assurance by the Company that actual results achieved will be the same in whole or in part as those set out in the forward-looking statements. Furthermore, the forward-looking statements contained in this document are made as of the date hereof, and the Company does not undertake any obligation, except as required by applicable securities legislation, to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement.


John Festival – President and Chief Executive Officer
Tel.: (403) 215-8313Don Cook – Chief Financial Officer
Tel: (403) 215-8313
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