BlackPearl Resources Inc.
TSX : PXX
OMX : PXXS

BlackPearl Resources Inc.

May 03, 2017 17:00 ET

BlackPearl Announces First Quarter 2017 Financial and Operating Results

CALGARY, ALBERTA--(Marketwired - May 3, 2017) - 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, 2017.

Highlights include:

  • The Board of Directors sanctioned the expansion of our successful Onion Lake thermal project in Saskatchewan and construction began on the second 6,000 barrel per day phase of the project. Target date for completion of construction and first steam is mid-2018. Peak production rates are expected 9 to 12 months thereafter.
  • Production averaged 10,753 barrels of oil equivalent (boe) per day, a 17% increase compared to Q1 2016 volumes. The increase is attributable to the production ramp-up on the Onion Lake thermal project, which produced 6,182 bbls/d in Q1 2017. Additionally, during the first quarter we re-started a portion of the alkali surfactant polymer (ASP) flood at Mooney.
  • Oil and natural gas revenues increased 186% in the first quarter of 2017 to $37.2 million from $13.0 million in the same period in 2016.
  • Net income in Q1 2017 was $7.8 million compared to a loss of $9.3 million in Q1 2016. Funds flow from operations increased to $12.9 million from $3.3 million in 2016.
  • The Company maintained its strong financial position with no debt at the end of the quarter and positive working capital of $3.6 million.
  • The Blackrod SAGD pilot continues to provide very positive results; over the last 24 months the pilot has produced an average of 550 bbls/d with a steam oil ratio under 3.

John Festival, President of BlackPearl commented, "We are well underway with construction of phase two of our thermal project at Onion Lake. Equipment modules are over 50% complete and we expect to start field assembly and drilling in the summer. Our success with the first phase of the Onion Lake thermal project has shown that these long-life, lower cost thermal projects in Saskatchewan provide some of the best economics in industry even in a lower commodity price environment. This success has allowed us to grow our production and lower our cost structure and we expect this will continue with our expansion of thermal development at Onion Lake."

Financial and Operating Highlights

Three months ended
March 31
2017 2016
Daily sales volumes
Oil (bbl/d) 10,105 8,422
Bitumen (bbl/d) (1) 542 584
Combined 10,647 9,026
Natural gas (mcf/d) 638 845
Combined (boe/d) (2) 10,753 9,166
Product pricing ($)
Crude oil - per bbl 40.75 16.77
Natural gas - per mcf 2.50 1.77
Combined - per boe 40.48 16.67
Operating netback ($/boe)
Sales 40.48 16.67
Realized gains on risk management contracts 0.37 7.84
Subtotal 40.85 24.51
Royalties 5.90 1.72
Transportation costs 2.67 2.68
Operating costs 15.00 12.35
Netback (5) 17.28 7.76
($000's, except per share and boe amounts)
Revenue
Oil and gas revenue - gross 37,204 13,021
Net income (loss) for the period 7,814 (9,322)
Per share, basic and diluted 0.02 (0.03)
Funds flow from operations(3) 12,924 3,278
Cash flow from operating activities (4) 14,786 3,787
Capital expenditures 13,356 2,077
Working capital deficiency (surplus), end of period (3,576) (9,155)
Long term debt - 86,000
Net debt (6) (3,576) 76,845
Shares outstanding, end of period 336,195,568 335,638,226
(1) Includes production from the Blackrod SAGD pilot. All sales and expenses from the Blackrod SAGD pilot are being recorded as an adjustment to the capitalized costs of the project until the technical feasibility and commercial viability of the project is established.
(2) 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.
(3) 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.
(4) Cash flow from operating activities is a GAAP measure and has a standardized meaning prescribed by Canadian GAAP.
(5) Netback is a non-GAAP measure that does not have a standardized meaning prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies.
(6) Net debt is a non-GAAP measure that does not have a standardized meaning prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies.

Operations Review

Onion Lake
During the first quarter we commenced construction of the 6,000 bbl/d expansion of our thermal project. Similar to the first phase, we entered into a fixed sum contract for all of the major equipment modules for the central processing facilities and pad facilities. The fixed sum contract represents approximately 40% of the anticipated total costs of the expansion. These equipment modules are being built in a fabrication shop near Calgary and will be transferred to site when completed. Field construction and assembly of the equipment modules is expected to commence in the third quarter. In addition, during the first quarter we drilled water source wells which will be used to supply water for steam generation for the project and we began site preparation for the central processing facilities.

The thermal expansion at Onion Lake will utilize a combination of a modified SAGD process (using existing and new vertical wells as steam injectors and horizontal producers), which was used for phase one and the more traditional SAGD process (two horizontal wells drilled approximately 5 metres apart). The advantage of using vertical injectors is that it utilizes existing wellbores and provides us with the flexibility to steam upper hole zones at a later date. Initially, we are planning to drill 14 horizontal producer wells, three horizontal steam injector wells and 20 vertical injector/observation wells. Drilling these wells represent about 200 days of drilling time and is expected to commence in the summer.

The Company's target for initial steam injection for the second phase is mid-2018. Peak oil production rates are expected 12 months after commencement of steam injection, which is similar to what we experienced for the first phase of thermal development. Capital costs for the second phase of this thermal project are estimated to be between $180 and $185 million, which is approximately 20% lower than the construction costs for the first phase.

We are continuing to see excellent production results from the first phase of the Onion Lake thermal project. During the first quarter of 2017 oil production averaged nearly 6,200 bbl/d with a steam oil ratio (SOR) of 2.5. Cumulatively, the thermal project has produced in excess of three million barrels of oil. Oil production will be impacted during the second quarter as a result of a facility turnaround and inspection in May. In addition, during the drilling of the wells for the second phase of the project we will have to limit steam injection in nearby phase one wells which will also temporarily impact oil production volumes.

Blackrod
At Blackrod, we did not undertake any new activities during the first quarter of 2017; however, our existing SAGD pilot is continuing to perform exceptionally well. During Q1 2017, production from the pilot averaged 542 bbl/d. Over the last two years the pilot has produced an average of 550 bbl/d with an SOR under 3. Cumulatively, the SAGD well pair has produced over 525,000 barrels of oil. We are planning to continue to operate the pilot as we are still acquiring valuable technical and operational data that will be helpful designing a commercial project for the area.

We have commercial development approval for an 80,000 bbl/d project on our Blackrod lands. At current commodity prices, expansion of our Onion Lake project is economically more attractive than our other projects; however, our Blackrod lands contain significant amounts of oil and we are confident that as oil prices improve development of Blackrod will provide excellent long term value to our shareholders.

Mooney
At Mooney, as a result of the improvement in oil prices late last year and early in 2017 and changes to our operating procedures we decided to re-initiate the ASP (Alkalie, Surfactant, Polymer) flood over a portion of the phase one ASP flood lands. Operating costs tend to be higher for an ASP flood due to the cost of chemicals for injection and we had temporarily shut-in the ASP flood in early 2016 due to low commodity prices. During the quarter we restarted ASP injection in 20 horizontal wells. Production from the Mooney area increased in the first quarter as a result of the start-up of the flood; however, it is expected to take several months to see the full impact of the flood on Mooney production volumes. In total, we have 34 wells on production in the Mooney area.

Production
Oil and gas production averaged 10,753 barrels of oil equivalent per day in the first quarter of 2017, a 17% increase compared with the first quarter of 2016. The increase reflects the successful ramp-up of production from our Onion Lake thermal project.

Production in our non-thermal areas increased in the first quarter of 2017 compared to the fourth quarter of 2016. With the improvement in crude oil prices we selectively brought back on production several shut-in wells at Onion Lake and re-initiated a portion of the ASP flood at Mooney. At Onion Lake, we still have approximately 500 barrels of oil per day currently shut-in.

Average Daily Sales Volume

Production by area (boe/d) Q1 2017 Q4 2016 Q1 2016
Onion Lake - thermal 6,182 6,119 4,252
Onion Lake - conventional 2,147 2,011 2,232
Mooney 942 785 1,042
John Lake 808 837 861
Blackrod 542 523 584
Other 132 204 195
10,753 10,479 9,166

Financial Results
Oil and natural gas sales increased 186% in the first quarter of 2017 to $37.2 million from $13.0 million in the same period in 2016. The increase in oil and gas sales is attributable to a 143% increase in average sale price received and a 17% increase in production volumes (on a boe basis).

Our realized oil price (before the effects of risk management activities) in Q1 2017 was $40.75 per barrel compared to $16.77 per barrel in 2016. The increase in our realized wellhead price reflects higher WTI oil prices in Q1 2017 compared with Q1 2016 (US$51.91/bbl vs US$33.45/bbl), partially offset by a stronger Canadian dollar relative to the US dollar ($0.756 vs $0.727) and slightly wider heavy oil differentials (US$14.61/bbl vs US$14.32/bbl).

During the first quarter we also realized a small gain of $0.3 million from our oil hedging program, which was the equivalent of adding $0.37 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
Type
2017
Oil 500 bbls/d April 1 to December 31 CDN$ WCS CDN$ 54.30/bbl Swap
Oil 500 bbls/d April 1 to December 31 CDN$ WCS CDN$ 52.75/bbl Swap
Oil 500 bbls/d April 1 to December 31 US$ WCS US$ 40.15/bbl Swap
Oil 1,000 bbls/d April 1 to December 31 CDN$ WCS CDN$ 50.00/bbl Swap
Oil 1,000 bbls/d April 1 to December 31 CDN$ WCS CDN$ 49.50/bbl Swap
Oil 500 bbls/d April 1 to June 30 CDN$ WCS CDN$ 40.00/bbl to 52.50/bbl Collar
Oil 500 bbls/d April 1 to June 30 CDN$ WCS CDN$ 40.00/bbl to 47.00/bbl Collar
Oil 1,000 bbls/d April 1 to December 31 US$ WTI US$ 60.00/bbl Sold Call
Oil 500 bbls/d July 1 to December 31 CDN$ WCS CDN$ 53.10/bbl Swap
Oil 500 bbls/d July 1 to December 31 CDN$ WCS CDN$ 53.00/bbl Swap
2018
Oil 500 bbls/d January 1 to December 31 US$ WTI US$ 70.00/bbl Sold Call

Total production costs increased 43% in the first quarter of 2017 to $13.8 million from $9.6 million in the same period in 2016. On a per boe basis, total production costs increased 21% in the first quarter of 2017 to $15.00 per boe from $12.35 per boe in the same period in 2016.

Thermal production costs at Onion Lake were fairly consistent between the first quarter of 2017 and the fourth quarter of 2016. During the first quarter of 2017 thermal production costs averaged $8.85 per barrel compared with $8.35 per barrel in Q4 2016 and $10.58 per barrel in Q1 2016.

The increase in total production costs during the first quarter of 2017 was primarily attributable to an increase in production costs on our non-thermal properties. The re-initialization of the ASP flood at Mooney resulted in an increase in chemical and injection costs during the quarter. In addition, we incurred workover costs on the wells we restarted at Mooney and Onion Lake. During the first quarter of 2017 production costs on our non-thermal properties averaged $24.43 per barrel compared with $18.59 per barrel in Q4 2016 and $14.09 per barrel in Q1 2016. Operating costs on our non-thermal properties are expected to decrease during the remainder of the year as our workover activities return to normal levels.

Funds flow from operations in Q1 2017 was $12.9 million compared with $3.3 million in the first quarter of 2016. The increase reflects significantly higher revenues partially offset by higher royalties, operating costs and G&A costs. Net income for the quarter was $7.8 million compared to a loss of $9.3 million in Q1 2016.

Capital spending was $13.4 million during Q1 2017, with the majority of costs spent on the expansion of the Onion Lake thermal project. In addition, during the quarter we sold some minor non-producing assets for proceeds of $3.4 million.

At March 31, 2017, the Company had no bank debt and had working capital of $3.6 million. The total credit facilities available to the Company are currently $117.5 million. The lenders next review of these facilities will be completed by May 31, 2017.

Outlook - Guidance

Our plan for the remainder of 2017 is relatively unchanged with the focus being the expansion of the Onion Lake thermal project with a target completion date of mid-2018. We are planning to spend between $185 and $190 million on capital projects, down from our initial guidance of $200 million. The decrease in capital spending is the result of deferring drilling on some our conventional heavy oil projects at John Lake, Onion Lake and other minor project areas to future periods, as well as adjusting the timing of expenditures on the Onion Lake thermal expansion.

The capital program is expected to be funded from a combination of our anticipated funds flow from operations and our undrawn credit facilities. We are also looking to supplement these sources with additional term debt financing to provide us with financial flexibility during the construction phase. Funds flow from operations is expected to be between $55 and $60 million, down from our initial guidance of $65 to $70 million. The decrease in funds flow from operations reflects a change in the average wellhead price we expect to receive for the remainder of the year. Year-end 2017 debt levels are anticipated to be between $130 and $135 million, down from our initial guidance of $135 and $140 million. The decrease in year-end debt levels reflects a decrease in capital spending for the remainder of the year. We anticipate oil and gas production to average between 10,000 and 11,000 boe/d in 2017, unchanged from our initial guidance.

The 2017 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 (www.blackpearlresources.ca) or SEDAR (www.sedar.com).

Non-GAAP Measures
Throughout this release, the Company uses terms "funds flow from operations", "operating netback" and "net debt". These terms do not have any standardized meaning as prescribed by GAAP and, therefore, may not be comparable with the calculation of similar measures presented by other issuers.

Funds flow from operations is calculated based on cash flow from operating activities before decommissioning costs incurred and changes in non-cash working capital related to operations. Management utilizes funds flow from operations as a key measure to assess operating performance and the ability of the Company to finance operating activities, capital expenditures and debt repayments. Funds flow from operations is not intended to represent cash flow from operating activities or other measures of financial performance in accordance with GAAP. The following table reconciles non-GAAP measure funds flow from operations to cash flow from operating activities, the nearest GAAP measure.

Three months ended
March 31,
($000s) 2017 2016
Cash flow from operating activities 14,786 3,787
Add (deduct):
Decommissioning costs incurred 42 147
Changes in non-cash working capital related to operations (1,904) (656)
Funds flow from operations 12,924 3,278

Operating netback is calculated as oil and gas revenues less royalties, production costs and transportation costs on a dollar basis and divided by total production for the period on a boe basis. Oil and gas revenues exclude the impact of realized gains on risk management contracts. Operating netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance against prior periods on a comparable basis. Our operating netback calculation is consistent with the definition found in the Canadian Oil and Gas Evaluation (COGE) Handbook.

Net debt is calculated as long-term debt plus working capital for the period ended. Working capital consists of cash and cash equivalents, trade and other receivables, inventory, prepaid expenses and deposits, fair value of risk management assets less accounts payable and accrued liabilities, current portion of decommissioning liabilities, deferred consideration and fair value of risk management liabilities. Management utilizes net debt as a key measure to assess the liquidity of the Company.

Forward-looking Statements
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, this release contains forward-looking statements pertaining to the estimated capital costs of between $180 to $185 million to construct phase 2 of the Onion Lake thermal project and the estimated mid-2018 completion date and estimated timing to reach peak production rates, estimated timing to see the full impact on production of the re-initiation of the ASP flood at Mooney, anticipated debt funding for the Phase 2 thermal expansion at Onion Lake and all the information under Outlook - Guidance.

The forward-looking information is based on, among other things, expectations and assumptions by management regarding its future growth, future production levels, future oil and natural gas prices, continuation of existing tax, royalty and regulatory regimes, foreign exchange rates, estimates of future operating costs, timing and amount of capital expenditures, performance of existing and future wells, recoverability of the Company's reserves and contingent resources, the ability to obtain financing on acceptable terms, availability of skilled labour and drilling and related equipment on a timely and cost efficient basis, general economic and financial market conditions, environment matters and the ability to market oil and natural gas successfully to current and new customers. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their nature, forward-looking statements involve numerous known and unknown risks and uncertainties that contribute to the possibility that actual results will differ from those anticipated in the forward looking statements. These risks include, but are not limited to, risks associated with fluctuations in market prices for crude oil, natural gas and diluent, general economic, market and business conditions, volatility of commodity inputs, substantial capital requirements, conditions including receipt of necessary regulatory and stock exchange approvals with respect to the issuance of common shares, 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, financial loss associated with derivative risk management contracts, potential cost overruns, variations in foreign exchange rates, variations in interest rates, diluent and water supply shortages, competition for capital, equipment, new leases, pipeline capacity and skilled personnel, uncertainties inherent in the SAGD bitumen and ASP recovery process, credit risks associated with counterparties, the failure of the Company or the holder of licences, leases and permits to meet requirements of such licences, 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. Readers are also cautioned that the foregoing list of factors is not exhaustive. Further information regarding these risk factors may be found under "Risk Factors" in the Annual Information Form.

Undue reliance should not be placed on these forward-looking statements. There can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based will be realized. Actual results will differ, and the differences may be material and adverse to the Company and its shareholders. Furthermore, the forward-looking statements contained in this release 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.

The information in this release is subject to the disclosure requirements of the Company under the EU Market Abuse Regulation and the Swedish Securities Markets Act. The information was publicly communicated on May 3, 2017 at 3:00 p.m. Mountain Time.

Contact Information

  • John Festival
    President and Chief Executive Officer
    (403) 215-8313

    Don Cook
    Chief Financial Officer
    (403) 215-8313

    Robert Eriksson
    Investor Relations Sweden
    +46 701-112615