Lundin Petroleum AB: Development Concept Selection Is Agreed for the Giant Johan Sverdrup Field
February 13, 2014 (Source: Marketwired) — Lundin Petroleum AB (TSX:LUP)(OMX:LUPE) (Lundin Petroleum), through its wholly owned subsidiary Lundin Norway AS (Lundin Norway), is pleased to announce that the partnerships for the Johan Sverdrup field have agreed a development concept for Phase 1 of the Johan Sverdrup field.
Further to Lundin Petroleum’s announcement on 20 December 2013, the final concept selection for Phase 1 of the development of the Johan Sverdrup field has now been decided by all partners in the Johan Sverdrup field, which spans across three licences: PL501, PL265 and PL502. Front end engineering for Phase 1 is currently ongoing and a plan of development will be submitted for approval by the Norwegian government in early 2015.
The full field gross recoverable contingent resource range of 1,800 to 2,900 million barrels of oil equivalent (MMboe), announced by the pre-unit operator Statoil Petroleum AS in December 2013, makes Johan Sverdrup one of the five largest fields discovered on the Norwegian Continental Shelf and when the field has reached forecast plateau production of 550,000 to 650,000 barrels of oil equivalent per day (boepd), field production is likely to represent around 25 percent of all Norwegian oil production.
Phase 1 – Field centre
Due to Johan Sverdrup’s size and lateral extension over a 200 km2 area, the field will be developed in several phases and with multiple fixed platform installations. Phase 1 of the development will contain the field centre of four fixed platform installations as well as additional subsea installations. The field centre will consist of one processing platform, one riser platform, one wellhead platform with drilling facilities and one living quarter platform. The platforms, which will be installed in 120 metres of water, will be installed on steel jackets and will be bridge-linked.
The first phase of the development is scheduled to start production in late 2019 and is forecast to have a gross production capacity of between 315,000 and 380,000 boepd. It is anticipated that between 40 and 50 production and injection wells will be drilled to support Phase 1 production, of which 11 to 17 wells will be drilled prior to first oil with a semi-submersible rig to facilitate Phase 1 plateau production.
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The gross capital investment for Phase 1, which includes oil and gas export pipelines as well as a power supply from shore, is estimated to between NOK 100 to 120 billion, including contingencies and certain market allowances for potential future increases in market rates. The Phase 1 field centre will also facilitate certain spare capacity for future phases and potential enhanced recovery. The licence partners are continuously working to lower the level of investment for Phase 1.
The Johan Sverdrup oil and gas production will be transported to shore via dedicated oil and gas pipelines. A 274 km 36″oil pipeline will be installed and connected to the Mongstad oil terminal on the west coast of Norway. A 165 km 18″ gas pipeline will be installed and connected to the Kårstø gas terminal for processing and onward transportation. The export pipelines are estimated to cost gross NOK 11 billion.
The Johan Sverdrup resources not developed as part of Phase 1 will be developed through subsequent development phases. The scope and costs of further development phases has not yet been addressed by the Johan Sverdrup partners and will form the basis of later investment decisions.
Ashley Heppenstall, President and CEO of Lundin Petroleum comments: “Following the discovery of the Johan Sverdrup field by Lundin Petroleum in 2010 the concept selection decision is a major milestone for Lundin Petroleum, our Johan Sverdrup partners and the Norwegian society. The development of this field will be one of the largest project undertakings in the North Sea since the 1980s. The quality, size and location of this field are a unique combination and as a result we believe it will create significant value for all stakeholders. It is often quoted in the oil industry that big oil fields get bigger and we certainly believe that this will be the case for Johan Sverdrup. On the Norwegian Continental Shelf a number of the larger mature fields are achieving recovery factors at or exceeding 70 percent and it will be the objective to achieve similar results for Johan Sverdrup.”
Lundin Norway is the operator of PL501 with a 40 percent interest, and has a 10 percent interest in PL265. The PL501 partners are Statoil Petroleum AS with a 40 percent interest and Maersk Oil Norway AS with a 20 percent interest. The PL265 partners are Statoil Petroleum AS, operator of PL265, with a 40 percent interest, Det norske oljeselskap ASA with a 20 percent interest and Petoro AS with a 30 percent interest. Lundin Norway has no interest in PL502. The PL502 partners are Statoil Petroleum AS, operator of PL502, with a 44.44 percent interest, Petoro AS with a 33.33 percent interest and Det norske oljeselskap ASA with a 22.22 percent interest.
Lundin Petroleum will hold a conference call today, Thursday 13 February 2014 at 11.00 CET (10.00 GMT) where Ashley Heppenstall, CEO, Lundin Petroleum will comment.
To listen to the presentation and participate in the questions and answer session, please dial:
Sweden: +46 8 505 564 74
International: +44 203 364 53 74
International toll free number: +1 855 753 2230
The slides for the presentation will be posted on Lundin Petroleum’s website prior to the conference call, www.lundin-petroleum.com.
Facts about the Johan Sverdrup field (PL 265, PL 501 and PL502)
- Johan Sverdrup is an oil field discovered by Lundin Petroleum in 2010.
- Johan Sverdrup consists of a combined discovery which makes up one field.
- Location: Utsira High in the Norwegian North Sea, 140 kilometres west from Stavanger.
- The water depth is 110 metres, and the reservoir depth is around 1,900 metres below mean sea level.
- Expected approval of the plan for development and operation (PDO) for Phase 1 during the Norwegian Parliament’s (Stortinget) spring session in 2015.
- Production start is expected at the end of 2019.
- The field has a production horizon until 2050.
- As part of the design basis it was decided early in 2013 that the field will be developed in phases. The first phase is the establishment of a field centre consisting of four platforms.
- The oil will be transported via pipeline to the Mongstad terminal in Hordaland, and the gas will be transported to Statpipe and then further to the Kårstø processing plant in northern Rogaland.
- The field will receive power from shore.
Lundin Petroleum is a Swedish independent oil and gas exploration and production company with a well balanced portfolio of world-class assets primarily located in Europe and South East Asia. The Company is listed at the NASDAQ OMX, Stockholm (ticker “LUPE”) and at the Toronto Stock Exchange (TSX) (Ticker “LUP”). Lundin Petroleum has proven and probable reserves of 194 million barrels of oil equivalent (MMboe).
This information has been made public in accordance with the Securities Market Act (SFS 2007:528) and/or the Financial Instruments Trading Act (SFS 1991:980).
Certain statements made and information contained herein constitute “forward-looking information” (within the meaning of applicable securities legislation). Such statements and information (together, “forward-looking statements”) relate to future events, including the Company’s future performance, business prospects or opportunities. Forward-looking statements include, but are not limited to, statements with respect to estimates of reserves and/or resources, future production levels, future capital expenditures and their allocation to exploration and development activities, future drilling and other exploration and development activities. Ultimate recovery of reserves or resources are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.
All statements other than statements of historical fact may be forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute forward-looking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and similar expressions) are not statements of historical fact and may be “forward-looking statements”. Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. No assurance can be given that these expectations and assumptions will prove to be correct and such forward-looking statements should not be relied upon. These statements speak only as on the date of the information and the Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among other things, operational risks (including exploration and development risks), productions costs, availability of drilling equipment, reliance on key personnel, reserve estimates, health, safety and environmental issues, legal risks and regulatory changes, competition, geopolitical risk, and financial risks. These risks and uncertainties are described in more detail under the heading “Risks and Risk Management” and elsewhere in the Company’s annual report. Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive. Actual results may differ materially from those expressed or implied by such forward-looking statements. Forward-looking statements are expressly qualified by this cautionary statement.
Reserves and Resources
Unless otherwise stated, Lundin Petroleum’s reserve and resource estimates are as at 31 December 2013, and have been prepared and audited in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”). Unless otherwise stated, all reserves estimates contained herein are the aggregate of “Proved Reserves” and “Probable Reserves”, together also known as “2P Reserves”. For further information on reserve and resource classifications, see “Reserves, Resources and Production” in the Company’s annual report.
Contingent Resources are 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. There is no certainty that it will be commercially viable for the Company to produce any portion of the Contingent Resources.
Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both a chance of discovery and a chance of development. There is no certainty that any portion of the Prospective Resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the Prospective Resources. Unless otherwise stated, all Prospective Resource estimates contained herein are reflecting a P50 Prospective Resource estimate. Risked Prospective Resources reported herein are partially risked. They have been risked for chance of discovery, but have not been risked for chance of development.
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf : 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.