Proved reserves and changes in proved reserves are estimated in accordance with SEC definitions. As of 31 December 2009 Statoil adopted revisions to the SEC's Rule 4-10 of Regulation S-X on the definitions of reserves. For additional information see "Critical accounting judgements and key sources of estimation uncertainty; Proved oil and gas reserves" in note 2 Significant accounting policies to the Consolidated Financial Statements. For prior period figures, see Supplementary oil and gas information in note 35 to the Consolidated Financial Statements. The reserves replacement ratio is defined as the sum of additions and revisions of proved reserves, divided by produced volumes in any given period.

Summary of oil and gas reserves as of 31 December 2009 based on average fiscal-year prices.

Changes in proved reserves estimates most commonly originate from revisions of estimates due to observed production performance, extensions of proved areas through drilling activities, or the inclusion of proved reserves in new discoveries through the sanctioning of development projects. These are sources of additions to proved reserves that result from continuous business processes and could be expected to continue to add reserves at some level in the future. Proved reserves can also be added or subtracted through acquisitions or disposals of assets.

Changes in proved reserves can also be due to factors outside management control, such as changes in oil and gas prices. Proved reserves as of 31 December 2009 have been determined based on a 12 month average price, whereas proved reserves for previous years are based on year end prices. While higher oil and gas prices normally allow more oil and gas to be recovered from the accumulations, Statoil's proved oil and gas reserves under PSAs and similar contracts will generally decrease as a result. Statoil will receive smaller quantities of oil and gas under the cost recovery and profit sharing arrangements of these contracts as a result of increased oil and gas prices. These changes are included in the revisions category in the table below.

In Norway, reserves are booked as proved when a development plan is submitted, since there is reasonable certainty that such a plan will be approved by the regulating authorities. Outside of Norway, reserves are booked as proved when regulatory approval is received, or when such approval is imminent. New discoveries with reserves booked in 2009 all start production in the period from 2009 to 2013. Reserves from new discoveries, upward revisions of reserves and purchases of proved reserves are expected to contribute to maintaining proved reserves in future years.

Additions that have contributed to our proved reserves in 2009 are:

Extension and discoveries that have increased our proved reserves in 2009 are:

• The Goliat field in the Bartents Sea in Norway, Kizomba satellites phase 1 in Angola and the Caesar Tonga Unit in Gulf of Mexico, USA, were sanctioned in 2009.
• The Beta Vest structure, an extension to the Sleipner Vest field, proved hydrocarbons by drilling in 2009.
• The Gimboa field in Angola commenced test production in April 2009.
• The PSVM development in Angola was approved by the concessionaire in 2008 and is carrying proved reserves in 2009.
• The Marcellus Shale Gas play in the USA, part of our gas value chain strategy, carries proved reserves in 2009.

Approval of future development plans for several of our producing fields on the NCS has contributed positively to revision of proved reserves:

• On the Oseberg field, a decision to upgrade existing drilling facilities allows for more wells to be drilled, resulting in increased reserves.
• On the Rimfaks field, a decision of pressure depleting the Brent reservoir has increased the reserves.
• On the Kvitebjørn field, a project has been approved that will allow for production at lower reservoir pressure through installation of a compressor module, thereby increasing the reserves.

In December 2008, the SEC issued new rules for reporting of oil and gas reserves by revising the definition of proved reserves. The technical aspects of the new rules have affected our proved reserves from certain fields:

• At the Kai Kos Dehseh leases in the Athabascan area in Canada, the Leismer Demonstration Project is able to book proved reserves for the first time, referring to several analogous reservoirs in the Athabascan area where reserves are currently produced using the SAGD technology. The project was sanctioned in 2008 and is scheduled to start production in 2010.
• Future extension of the licence period is now assumed reasonably certain on the NCS, increasing the proved reserves for certain fields.
• Some fields, previously limited by lowest known hydrocarbons, have been included in the proved reserves based on a lower contact established with reasonable certainty based on reliable technology.

The effect of the new rules on our total proved reserves is however immaterial and is estimated to be less than 2%. This estimate includes the effect of the change in product price to be used, from year end price to a 12 month average price.

Below is a table showing the reserves additions in each change category relating to the reserve replacement ratio for the years 2009, 2008 and 2007.

The reserves replacement ratio was 73% in 2009, compared with 34% in 2008. The increase in the reserves replacement ratio in 2009 compared with 2008 is mainly due to 2009 being a year with more reserves additions from new fields and sanctioned future development plans for producing fields. The average replacement rate for the last three years was 64%, including purchases, sales and reduction of the shareholding in Petrocedeño in 2008.

The usefulness of the reserves replacement ratio is limited by the volatility of oil prices, the influence of oil and gas prices on PSA reserve booking, the sensitivity related to the timing of project sanctions, and the time lag between exploration expenditure and booking of reserves.

Preparation of reserves estimates

Statoil's annual proved reserves reporting process is coordinated by a central group of experts. This group is called Corporate Exploration and Production Forecasting (CEPF) and consists of experts within geosciences, reservoir and production technology and financial evaluation with on average more than 20 years of experience from the oil and gas industry. The CEPF group reports to the Vice President of Finance and Control in the Technology and New Energy business area and is thus independent of both E&P Norway and the International E&P business areas.

Although this group reviews the information centrally, each asset team is responsible for ensuring that it is in compliance with the requirements of the SEC and our corporate standards. Information about proved oil and gas reserves, standardised measures of discounted net cash flows related to proved oil and gas reserves and other information related to proved oil and gas reserves, is collected from the assets and checked for consistency and conformity with applicable standards by CEPF. The final numbers for each asset are quality controlled and signed off by the responsible asset manager before aggregation to required reporting level by CEPF.

The aggregated results are brought forward for approval to relevant Business Area management teams and the corporate executive committee and finally presented to the board of directors.

The technical person primarily responsible for overseeing the preparation of the reserves estimates is the manager of the CEPF group. The person who presently holds this position has a Bachelor's Degree in Earth sciences from the University of Gothenburg, and a Master's degree in Petroleum Exploration and Exploitation from Chalmers University of Technology in Gothenburg, Sweden. She has 24 years of experience in the oil and gas industry of which 23 are within Statoil. She is a member of the Norwegian Petroleum Society and a vice chairperson of the UNECE Expert Group on Resource Classification (EGRC).

Development of reserves

Total quantity of proved undeveloped oil and gas reserves as of 31 December 2009 was 1 295 mmboe of which 63% is related to fields in Norway. Significant undeveloped reserves are related to large gas fields on the NCS with continuous development activity, such as Troll, Snøhvit, Tyrihans, Visund and Ormen Lange.

Due to the nature of large fields with continuous development activity such as Troll and Snøhvit in Norway, Azeri-Chirag-Gunashli in Azerbaijan and Petrocedeño in Venezuela, these fields contain reserves that remain undeveloped for five years or more. The Troll phase 3 development activity includes start-up of production from additional wells in 2024 while the Snøhvit development activity includes start-up of production from additional wells in the Askeladden structure in 2017, both to maintain the plateau production. The development activity for Azeri-Chirag-Gunashli and Petrocedeño include continuous drilling beyond 2015.

Fields under development but not yet in production, such as Skarv, Gjøa and Goliat in Norway, CaesarTonga in GoM USA, Corrib in Ireland, Leismer Demonstration Project in Canada, Peregrino in Brazil and Kizomba satellites in Angola represent approximately 30% of the total proved undeveloped reserves at year end 2009.

The sanctioning of new projects such as CaesarTonga in the GoM and Marcellus in the USA, Goliat in Norway, the Leismer Demonstration Project in Canada and the Kizomba satellites and PSVM in Angola added a total of 128 mmboe of proved undeveloped reserves in 2009. Start of production and further development of producing fields contributed to converting reserves from undeveloped to developed. The net change in proved undeveloped reserves during 2009 represents a reduction of 60 mmboe.

Start of production from the fields Alve, Yttergryta and Tyrihans in Norway, Tahiti and Thunder Hawk in GoM USA, Marcellus in USA and Gimboa in Angola increased our developed reserves by 224 mmboe in 2009. Most of this increase came from converting undeveloped reserved into developed reserves.

In 2009 Statoil incurred NOK 56.9 billion in development costs related to assets carrying proved reserves, of which NOK 29.9 billion were related to moving proved undeveloped reserves to developed.

Additional information about proved oil and gas reserves are reported in note 35 - Supplementary oil and gas information - to our Consolidated Financial Statements.

Delivery commitments

From the Norwegian Continental Shelf (NCS) Statoil is required, on behalf of the Norwegian State's direct financial interest (SDFI), to manage, transport and sell the Norwegian State's oil and gas. These reserves are sold in conjunction with our own reserves. As part of this arrangement, Statoil will deliver gas to customers in accordance with various types of sales contracts. In order to fulfil the commitments, Statoil will utilise a field supply schedule which provides the highest possible total value for the joint portfolio of oil and gas between Statoil and SDFI. 

As at 31 December 2009, the Statoil/SDFI arrangement amounted to a total of 29.5 tcf (835 bcm) in total expected gas commitments on the NCS. The principles for booking of proved reserves are limited to contracted gas sales or gas with access to a robust gas market.

The majority of Statoil's gas volumes are sold under long term contracts with Take or Pay clauses. For each individual year, Statoil and SDFI express their delivery commitments as the sum of the Annual Contract Quantity (ACQ). In the contract years 2009 to 2012, the joint ACQ for the respective years are; 2.50, 2.43, 2.39, and 2.40 tcf. The majority of delivery commitments will be fulfilled by production from our existing proved reserves from fields where Statoil and/or SDFI participates, while any shortfalls would be covered by sourcing existing gas markets.