BlackPearl Announces First Quarter 2013 Financial and Operating Results

CALGARY, ALBERTA--(Marketwired - May 8, 2013) - 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, 2013.

Highlights include:

• Drilled the second pilot SAGD well pair at Blackrod. Steam injection in this well will begin in the summer. We are continuing to optimize our production techniques with the first well pair, with the most recent modifications production from the well is headed back towards commercial rates. We continued with detailed engineering for the first phase of commercial development;
  
  
• We acquired an additional 10 sections of oil sands acreage in April adjacent to our existing Blackrod leases. Internal estimates indicate this acquisition could add 50 to 75 million barrels of contingent resources (best estimate) ⁽¹⁾ to the project;
  
  
• Continued conventional heavy oil development at Onion Lake with eleven wells drilled in the first quarter. Regulatory review for the planned 12,000 barrel per day thermal project is nearing completion, approval is anticipated in the second quarter;
  
  
• The ASP flood at Mooney is performing as expected. Total Mooney area production (flooded and non-flooded areas) increased 90% year-over-year to 3,892 barrels of oil per day. We plan to expand the flood in 2014;
  
  
• Wide heavy oil differentials impacted revenues and cash flow during Q1, revenues were $41 million and cash flow from operations was $10 million for the quarter. Differentials have returned to more normal levels in Q2;
  
  
• Due to lower capital investment in Q1 as a result of low heavy oil prices, our production averaged 9,087 barrels of oil equivalent per day in Q1, which was flat with our Q4 2012 production.
  
  

John Festival, President of BlackPearl, commenting on Q1 2013 activities, indicated that, "Although the impact of lower heavy oil prices seemed to dominate discussions during the quarter, operationally we continued to advance all three of our core properties. At Blackrod, following the achievement of commercial production rates from the first pilot SAGD well our focus changed to optimizing well performance and operating procedures specific to our reservoir. We will continue this optimization process with the second well pair. At Onion Lake, we have several more years of conventional heavy oil development but we have also made good progress with our thermal development plans in the area. In Saskatchewan, thermal heavy oil projects are typically smaller in scale than you see in the Alberta oil sands but they have excellent economics due to better reservoir parameters and better oil quality and mobility. At Mooney, phase one of the ASP flood is developing as expected and we are planning to drill additional phase two wells later this year followed by expansion of the ASP flood to the phase two area in 2014.

We are at an important stage in the advancement of our Company. We are ready to tackle development of our two thermal projects. Over the last few months the most often asked question from our shareholders and potential investors is how are we going to fund these projects. We have been working on financing options for both of our thermal projects. I believe we will be able to provide our shareholders with our financial path forward for these projects in the next couple of months."

Property Review

Blackrod SAGD Pilot Project

At Blackrod, we are continuing to monitor and learn from the pilot SAGD well pair we drilled in 2011. The well reached commercial production rates of 400 barrels of oil per day after 10 months of steam injection. At that point we elected to turn our attention to testing alternative operating strategies to better understand operating conditions specific to the Blackrod reservoir and optimize our production techniques as we move ahead with commercial development.

Managing sand production is an important aspect of producing SAGD wells to ensure we maximize well productivity and maintain lower well operating costs. The Blackrod pilot well has experienced reduced fluid productivity with the sand control process adopted for the first well pair, which has impacted oil production rates. We implemented a less restrictive sand control program late in the first quarter and we expect to be able to make a full assessment of the new process during the second quarter. Early results are positive as production from the well is headed back towards commercial rates.

During the first quarter we drilled a second pilot well pair at Blackrod. This well was drilled longer (950 metres) than the first pilot well pair and slightly deeper in the reservoir. Steam injection will begin in the summer with oil production expected six to twelve months after steam injection. We will continue to test alternative operating procedures with the second well pair to optimize operating processes before we initiate commercial development at Blackrod.

We are working with regulatory authorities as they review our application for the first phase of commercial development at Blackrod. This first phase of development is designed to be 20,000 barrels per day. The application was filed in May 2012, and regulatory review for these types of projects typically takes 18 to 24 months. We began detailed engineering work on the first phase of the commercial project in late 2012.

In April, we acquired 10 sections (6,400 acres) of additional oil sands acreage directly south of our existing Blackrod lands. We have not had our third party reserve and resource evaluator prepare an evaluation of these leases but we have internally estimated that best estimate contingent resources ⁽¹⁾ could range from 50 to 75 million barrels of bitumen. This acreage will be incorporated into our development plans for the Blackrod project.

As at December 31, 2012 the Blackrod leases had 2P reserves of 182 million barrels of oil and contingent resources (best estimate) of 476 million barrels assigned to them by our independent reservoir evaluators.

Onion Lake

At Onion Lake, we continued primary development of the field, drilling 11 conventional wells in the first quarter. These wells were completed and put on production during the quarter and will be optimized in the second quarter. We plan to drill an additional 10 to 15 wells during the remainder of 2013. In addition to the first quarter drilling, we completed a 2D seismic program over a southern extension to the main Onion Lake pool.

We have also been working closely with regulatory authorities on our 12,000 barrel per day thermal development application at Onion Lake. We anticipate receiving regulatory approval for the project in the second quarter. We are considering financing options that would allow us to accelerate development of the thermal project. Other operators have been very successful with these smaller but very prolific thermal projects in Saskatchewan. Well productivity is generally higher and steam oil ratios lower than typical oil sands thermal projects due to better reservoir parameters and oil quality.

Mooney

We continue to see a favourable response from the ASP flood at Mooney. The wells in the northern and central portion of the pool have seen the most rapid response from the ASP flood, which was expected due to better oil and reservoir quality in these areas. Response in the southern half of the pool is expected to be slower due to slightly heavier oil and lower reservoir quality.

We expanded the pool development at Mooney by drilling 15 horizontal wells last fall. We had planned to continue development drilling in the first quarter, however, due to the low price environment in the first quarter, we elected to defer this drilling (15 to 20 horizontal wells) until later in the year. We plan to expand the ASP flood to these newly drilled areas in 2014.

Current production at Mooney is nearly 4,000 barrels of oil per day and we anticipate this increasing to approximately 5,000 barrels of oil per day later this year as the pool continues to respond positively to ASP injection.

Production

Oil and gas production averaged 9,087 barrels of oil equivalent per day in the first quarter of 2013, a 5% decrease from the first quarter in 2012, but generally flat compared with Q4 2012 production levels. The decrease in production in 2013 is mainly attributable to natural production declines in the Onion Lake area, partially offset by increases from the response of the ASP flood at Mooney and the development of the non-flooded areas at Mooney.

Average Daily Sales Volume

		Three months ended March 31
(boe/day)		2013	2012
Onion Lake		4,322	6,732
Mooney
	ASP flood area	1,846	504
	Non-flood areas	2,046	1,522
John Lake		781	559
Other		19	23
		9,014	9,340
Blackrod SAGD pilot		73	241
		9,087	9,581

Financial Results

Oil and gas revenues decreased 30% in the first quarter of 2013 to $40.7 million compared with $57.8 million in Q1 2012. The decrease was primarily attributable to a decrease in heavy oil prices in 2013. Our realized heavy oil price was $50.64 per barrel in 2013 compared with $68.20 per barrel in 2012.This decrease reflects wider heavy oil differentials during Q1 2013.

Operating costs were $23.05 per boe in Q1 2013, which is an increase from previous quarters. The increase in 2013 is mainly due to us starting to expense injection and polymer costs associated with the ASP flood at Mooney. During the initial re-pressurization of the reservoir these costs were capitalized.

The decrease in wellhead prices and higher operating costs resulted in a decrease in cash flow from operations (before working capital adjustments and decommissioning costs) in Q1 to $10.0 million compared to $24.4 million for the same period in 2012.

Financial and Operating Highlights

		Three months ended March 31
		2013		2012
Daily production / sales volumes (1)
	Oil (bbl/d)	8,941		9,541
	Natural gas (mcf/d)	879		234
	Combined (boe/d)	9,087		9,581
Product pricing ($)
	Crude oil - per bbl	50.64		68.20
	Natural gas - per mcf	3.18		2.24
	Combined - per boe	50.13		67.98
($000's, except per share and boe amounts)
Revenue
Oil and gas revenue - gross		40,671		57,776
Royalties ($/boe)		7.80		15.60
Transportation costs ($/boe)		3.60		2.12
Operating costs ($/boe)		23.05		19.63
Net income (loss) for the period		(5,644	)	3,574
	Per share, basic and diluted	(0.02	)	0.01
Cash flow from operating activities, before working capital adjustments		10,039		24,365
Capital expenditures		19,101		43,469
Working Capital, end of period		(4,624	)	22,100
Long term debt		11,915		-
Shares outstanding, end of period		296,108,308		285,172,678

(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.

The 2013 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).

This news release includes terms commonly used in the oil and natural gas industry, such as cash flow and cash flow from operations which represent cash flow from operating activities expressed before 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.

Forward-Looking Statements

This news 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 historical fact are forward-looking statements. Forward-looking information typically contains statements with words such as "anticipate", "believe", "plan", "continuous", "estimate", "expect", "may", "will", "project", "should", "target", "forecast" or similar words suggesting future outcomes. In particular, this document contains forward-looking statements pertaining to the estimate of contingent resources on the new acreage acquired near Blackrod, timing of receiving development approvals for our Blackrod and Onion Lake SAGD projects, timing of finalizing funding options for our thermal projects, determination of commerciality of the Blackrod project, reserve and contingent resource estimates at Blackrod; estimated potential production levels of the ASP flood at Mooney, future drilling plans at Onion Lake and Mooney and timing of the expansion of the ASP flood at Mooney.

Statements relating to reserves and contingent resources are forward-looking, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and contingent resources described exist in the quantities predicted or estimated and can profitably be produced in the future.

Undue reliance should not be placed on forward-looking statements, which are inherently uncertain, are based on estimates and assumptions, and are subject to known and unknown risks and uncertainties (both general and specific) that contribute to the possibility that the future events or circumstances contemplated by the forward-looking statements will not occur. 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.

With respect to forward-looking statements contained in this press release, management has made assumptions regarding future production levels; future oil and natural gas prices; future operating costs; timing and amount of capital expenditures; the ability to obtain financing on acceptable terms; availability of skilled labour and drilling and related equipment; general economic and financial market conditions; continuation of existing tax and regulatory regimes; 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 very nature, forward-looking statements involve inherent risks and uncertainties (both general and specific) and risks that the goals or figures contained in forward-looking statements will not be achieved. These factors 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, 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 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.

Further information regarding these risk factors may be found under "Risk Factors" in the Annual Information Form. Readers are cautioned that these factors and risks are difficult to predict and that the assumptions used in the preparation of such information, although considered reasonably accurate at the time of preparation, may prove to be incorrect. Accordingly, 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 factors is not exhaustive. Consequently, there is no representation by the Corporation that actual results achieved will be the same in whole or in part as those set out in the forward-looking information. Furthermore, the forward-looking statements contained in this report are made as of the date hereof, and the Corporation 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.

(1) This news release makes reference to contingent resources. Contingent resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. In the case of the contingent resources assigned to BlackPearl's three core projects the contingencies include the requirement for more evaluation drilling to better define the resource, the absence of submission of commercial SAGD development applications (for future phases of development at Blackrod), the likelihood of attaining regulatory approvals for commercial SAGD development (for our Onion Lake SAGD project), further establishment of increased oil production response from the ASP flood at Mooney and the uncertainty of the timing of production and development. There is no certainty that it will be commercially viable to produce any of the contingent resources. Best estimate (P50) is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate. Please refer to our Annual Information Form for a more detailed discussion of our contingent resources.