FORM 20-F

(Mark One)

 

  

 

1 Introduction

 

1.1 About the report

Statoil's Annual Report on Form 20-F for the year ended 31 December 2015 ("Annual Report on Form
20-F") is available online at www.statoil.com. 

 

Statoil is subject to the information requirements of the US Securities Exchange Act of 1934 applicable to foreign private issuers. In accordance with these

requirements, Statoil files its Annual Report on Form 20-F and other related documents with the Securities and Exchange Commission (the SEC). It is also

possible to read and copy documents that have been filed with the SEC at the SEC's public reference room located at 100 F Street, N.E., Washington, D.C.

20549, US. You can also call the SEC at 1-800-SEC-0330 for further information about the public reference rooms and their copy charges, or you can

log on to www.sec.gov. The report can also be downloaded from the SEC website at www.sec.gov.

 

Statoil discloses on its website at www.statoil.com/en/about/corporategovernance/statementofcorporategovernance/pages/default.aspx, and in its Annual Report on Form 20-F (Item 16G) significant ways (if any) in which its corporate governance practices differ from those mandated for US companies under the New York Stock Exchange (the "NYSE") listing standards.

 

1.2 Key figures and highlights

 

Statoil publishes financial data in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and as adopted by the European Union (EU).

 

 

2 Strategy and market overview

 

The profitability of the oil and gas industry continues to be challenged and Statoil’s financial results in 2015 were influenced by the fall in oil prices. Stricter project prioritisation and a comprehensive efficiency programme are showing progress and are expected to continue to improve cash flow and profitability. Statoil proposes to the annual general meeting a scrip dividend from the fourth quarter of 2015. Statoil’s strong financial position provides a firm basis on which to balance capital investment and dividends to shareholders, which Statoil expects to grow in line with its long-term earnings.

 

Last year Statoil outlined plans to further strengthen its competitiveness, and is now reinforcing its effort and commitment to deliver on priorities of high value creation, increased efficiency and competitive shareholder returns. Through Statoil`s flexibility in its investment programme Statoil believes that it is well prepared for potential sustained market volatility and uncertainty.

 

Statoil’s ambition to further reduce costs and improve efficiency was presented at the capital markets update (CMU) on 6 February 2015. Then, the company announced that it was targeting annual savings of USD 1.7 billion from 2016 (pre-tax) as measured against the cost base of 2013. Having already realised $1.9 billion in savings (pre-tax), Statoil announced a new goal at the CMU on 4 February 2016. The company will step up its efficiency programme by 50% with a goal to realise USD 2.5 billion in annual savings from 2016 (pre-tax), again as measured against the cost base of 2013.  The step-up of $0.8 billion is expected to be divided by two-thirds capital expenditures (capex) and one-third operational expenditures (opex).

 

Improvement programmes are Statoil’s response to the industrial challenges characterised by high costs and declining returns. More specifically, the ambition is to realise positive production effects and cost savings to improve Statoil’s financial results and cash-flows.

 

These forward-looking statements reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future. See section 10 Forward-Looking Statements for more information. 

 

2.1 Statoil’s business environment

2.1.1 Market overview

 

Global economic GDP growth eased in 2015, to 2.4% from 2.6% in 2014. This largely reflects weakness in non-OECD economies where activity decelerated over the year. Growth in OECD, on the other hand, held up relatively well at around 2%, supporting overall economic growth and energy demand.

 

The underlying fundamentals of the United States economy remain sound and GDP growth ticked up slightly to 2.5% in 2015 from 2.4% in 2014. GDP growth also accelerated nominally in the Eurozone to 1.5%, supported by low energy prices, reduced fiscal headwinds, more monetary stimulus and a weak euro. UK GDP growth slowed in 2015, but remains decent at 2.4%, whereas Japan barely avoided its fourth recession in five years. Growth in emerging countries slipped to 3.6% in 2015, reflecting both weakness in commodity prices and domestic challenges. Deep recessions have emerged in Brazil and Russia, whilst China continues on an intended path of gradual deceleration and consequent structural reforms. Net commodity importers such as India are doing much better, and India’s GDP growth rate outpaced China’s in 2015.

 

Several major forces are at play in the global economy and will continue to affect demand, including soft commodity prices and persistently low interest rates, increasingly divergent monetary policies across major economies, and weak world trade. In particular, the sharp decline in oil prices since mid-2014 has supported global economic activity and is expected to continue to do so in 2016.

 

Global oil demand grew by a healthy 1.6 mmbbl per day in 2015, driven by a colder than normal winter in the US and Northern Europe and the lower prices of crude oil. Demand growth in absolute terms was highest in China, despite 2015 being a challenging year for Chinese stock markets and the Chinese economy in general. Non-Opec producers have proven to be resilient to lower prices and grew production by 1.3 mmbbl per day in 2015 while Opec added 1.1 mmbbl per day to their production, mainly from Saudi Arabia and Iraq. This has postponed the rebalancing between supply and demand and has led to a continued drop in oil prices.

 

2015 saw moderate growth in gas supply and demand of 1.5%, which is below the growth rates of the previous years. The United States is the main driver behind the growth. Europe experienced a weather-driven increase in demand as compared to 2014. Gas consumption declined in Japan and South Korea due to weak power sector gas demand caused by the (re)start of coal and nuclear power plants. Gas demand growth slowed in China and other emerging markets, with more competitively priced oil products being one contributing factor. In the United States, a multi-year wave of gas supply growth came to an end in 2015, but demand could not keep up with supply growth, and prices fell. A strong supply of pipeline gas to Europe and an emerging oversupply of LNG have further depressed gas prices.

 

 

 

The global economic situation continues to be fragile, with development partly driven by uncertain political environments in key countries and regions, in addition to normal supply and demand factors. The situation at the end of 2015, with high storage levels and low prices, will continue to put pressure on international oil companies to increase efficiency and reduce costs. This will contribute to a gradual rebalancing of markets for oil and gas. The impact of this on price levels and price developments is very uncertain.

 

2.1.2 Oil prices and refining margins

 

High volatility characterised the oil market in 2015, with the price of Brent in a range between USD 66 per barrel in May to USD 35 per barrel at the end of December. Refinery margins were well above normal levels due to low crude prices throughout the year.

 

Oil prices

The average price for dated Brent crude in 2015 was USD 53/bbl, down 47% from 2014. The price was at USD 55/bbl in the beginning of 2015, on a downward trajectory. A temporary low was reached at just above USD 45/bbl in the middle of January before the prices started climbing again. A positive market sentiment drove the price of dated Brent up in the second quarter. Signs of a downturn in the Chinese economy and the nuclear deal between P5+1 and Iran contributed to a declining market sentiment and prices fell again to a new low in August. The price of dated Brent recovered somewhat again in the 3^rd quarter and in to the 4^th quarter, before the 168^th Opec meeting on the 4^th of December. No action was agreed by the Opec member countries and the price of Brent went below USD 40/bbl for the first time since the spring of 2009. The dated Brent price was USD 36/bbl on 31 December 2015, a year-end level not seen for a decade. The futures market for Brent at the Intercontinental Exchange (ICE) was in contango throughout 2015. See section 9 Terms and definitions  for further details.

 

Although the conflict level in Syria increased further and the armed conflict in Yemen added tension in the Middle East, geopolitical events had less effect on the crude oil prices in 2015, compared with the previous year.

 

Opec’s decision, in late 2014, to not balance the market, marked the change of a 30-year old strategy. Subsequent to this the oil market was highly volatile throughout 2015, while the participants endeavoured to find the new price level of crude oil. Although oil demand increased by 1.6 mmbbl per day, much due to a cold winter and low prices, the market remained oversupplied throughout the whole year, with total supply growth of 2.4 mmbbl per day of production. As a consequence, the global oil stocks were at historically high levels by year-end. 

 

2015 was an eventful year for North American (NA) crude. The price of US WTI crude, as quoted at the Cushing tank farm in Oklahoma, averaged USD 49/bbl in 2015, down 47% from 2014. The price of WTI was USD 53/bbl at the beginning of the year. On 31 December 2015 the WTI price was at USD 37/bbl, roughly at par with first month Brent. With low crude prices through 2015, rig counts have dropped and production growth has faltered. At the same time, crude inventories have continued to grow, further weighing on crude prices. New pipeline and crude distillation capacity, coupled with slower production growth, have created a tighter balance for US light crude, easing the large price discounts of inland crudes relative to Brent. The easing of discounts has challenged the economics of more expensive transport solutions such as rail relative to pipeline, such that crude by rail loadings have declined dramatically during 2015. In late 2015, the US government passed legislation allowing unrestricted export of crude oil for the first time since the 1970s. While little impact is expected in the global market short term, given the current oversupplied global crude market, unrestricted US crude exports provides producers with greater access to higher value global crude markets and could impact price differentials.

 

Refining margins

Refinery margins in Northwest Europe, as calculated against dated Brent crude, were well above normal in 2015. One reason for the strength was the weak crude oil market, with dated Brent priced below the first forward month at the ICE exchange throughout the year. Further, the price differentials vs. Brent for the crude oils actually used were lower than last year. The other main factor was a very strong gasoline market. Low price levels at the pump led to rising demand in the US, and gasoline demand in Europe stopped falling. Changes to the Chinese economy led to more emphasis on the consumer sector. New car sales in China almost matched that of the US, and some 80% were net additions to the fleet. Chinese gasoline demand therefore rose almost as much as in the US, and strong growth was also seen in India and Pakistan. This demand growth led to capacity constraints at refineries, in particular for high-octane components. Europe, being in net surplus on gasoline, was able to export more into these markets, with parts of it going as high-octane components at strong price premiums. For naphtha, which is a feedstock both for the petrochemical industry and for making gasoline, Asian demand for imports from Europe rose through the year and gave very strong margins here. On the other hand, new refineries in Asia and the Middle East were geared towards diesel production. New diesel volumes exported to Europe led to rising inventory levels here, despite a quite strong demand growth. The situation became dramatic in the fourth quarter of 2015, when high refinery throughputs in order to make enough gasoline and naphtha led to excess diesel production. This made diesel tanks go full and the diesel margin decreased. LPG was oversupplied due to high exports from the US. Heavy fuel oil was oversupplied due to declining demand. However, against the low Brent crude oil prices, both products still saw quite normal margins.

  

 

2.1.3 Natural gas prices

 

Natural gas prices fell during 2015 in most markets. European gas prices reached the lowest level since early 2010. Reasons include weak demand, good supplies and low prices for coal, oil and other competing fuels. Henry Hub gas prices in the United States also declined during 2015, and the prices at year-end were at the lowest level since the 1990s.

 

Gas prices - Europe

European gas market prices averaged USD 6.5/mmBtu in 2015, down 20% from 2014. EU gas consumption for heating purposes recovered in 2015 as temperatures returned to more normal levels after a particularly mild winter in 2014. The use of gas for power generation increased in Southern Europe due to high summer temperatures, but declined in other parts of Europe. High availability of wind in 2015 and a steady growth in renewable generation capacity made inroads in the overall need for gas-fired and other thermal power plants in Europe.

 

Norwegian exports of pipeline gas reached record-levels of 108 bcm in 2015. EU indigenous gas production fell by 10% to 125 bcm as the Dutch government lowered existing production caps at the large Groningen field as a response to earthquake activity. Russia exported more than 150 bcm of pipeline gas to Europe in 2015, close to recent historical highs. Europe imported around 50 bcm LNG in 2015, more than in 2014, but still 35 bcm below the peak a few years ago.

 

Gas prices - North America

First quarter prices centered on USD 3/mmBtu, while second and third quarter prices fluctuated around USD 2.75/mmBtu, with weather-related ups and downs. However, in the fourth quarter prices fell and reached USD 1.50/mmBtu at the end of the year, as storage rose to new record highs and an El Niño weather event quashed demand in the winter peak season. As a result, the Henry Hub average of USD 2.6/mmBtu was the lowest annual price in over a decade, down from USD 4.4/mmBtu in 2014.

US gas producers responded to the falling prices by withdrawing rigs. Gas production peaked at the end of the summer and supply has been falling since. Demand for gas was strong in 2015, with natural gas for the first time exceeding coal use in the power sector for most of the year.

Global LNG prices

Global prices for LNG have plummeted. Prices under long-term LNG contracts to buyers in Asia are tracking oil prices with a lag, and contract prices were typically down 40% from 2014. The price assessment for spot LNG cargoes in Asia reached USD 7.5/mmBtu over the year compared to USD 14/mmBtu in 2014. LNG prices are now back to levels prior to the Fukushima nuclear disaster in March 2011. The global LNG market has entered a period where the growth of supplies from Australian, US and other liquefaction projects could exceed demand.

 

2.2 Statoil’s corporate strategy

 

Statoil creates value by accessing, exploring, developing, and producing energy sources globally, and by enhancing the value of such production through its mid- and downstream positions.

 

Fundamental changes are happening in the oil and gas industry. The industry faces new challenges, such as increased pressure on margins, changing patterns of energy supply and consumption, geopolitical instability and rising climate change concerns.

 

Statoil's top priorities remain to conduct safe and reliable operations with zero harm to people and the environment, and to grow value through disciplined investments and prudent financial management with competitive redistribution of capital to shareholders. To succeed going forward in turning Statoil’s vision into reality, Statoil pursues a strategy that will:

·          Deepen and prolong Statoil’s NCS position

·          Grow material and profitable international positions

·          Pursue focused and value-adding mid- and downstream activities

·          Provide energy for a low carbon future

 

In addition, Statoil will research, develop, and deploy technology to create opportunities and enhance the value of Statoil’s current and future assets.

 

 

Deepen and prolong Statoil’s NCS position

For more than 40 years, Statoil has explored, developed and produced oil and gas from the Norwegian continental shelf (NCS). Statoil aims to deepen and prolong its position by accessing and maturing opportunities into valuable production. At the same time Statoil plans to improve the reliability and lifespan of fields already in production.  

·          Exploration:  Statoil has proven to be a committed NCS explorer across mature, growth, and frontier areas. In the last year, Statoil participated in 21 completed exploration wells of which 10 were discoveries. Statoil announced discoveries in the Aasta Hansteen area, the Krafla area, and the King Lear area. Statoil applied for new acreage in the Barents Sea as part of the 23^rd licensing round and entered the Barents Sea Exploration Collaboration with four other oil and gas explorers to address common operational challenges. Statoil also applied for additional NCS licenses during the 2015 Awards in Predefined Areas (APA) with the results awarded in 2016

·          Development:  Statoil received approval from the Norwegian Ministry of Petroleum and Energy for the plan for development and operation (PDO) for Johan Sverdrup Phase I and awarded several related key contracts to suppliers. The development plan for Johan Sverdrup Phase II, along with other projects, continues to be matured. In 2015, Statoil delayed the concept selection for Johan Castberg, Snorre 2040 and Trestakk (sanctioned early 2016) to secure robust development solutions. Gina Krog’s expected start-up is now 2017 with the steel jacket having been installed and predrilling of the production wells started

·          Production:  Statoil began production from Valemon, Oseberg Delta 2, Gullfaks South Oil, Smørbukk South Extension and the Lundin-operated Edvard Grieg field. Three major projects to increase recovery have been delivered in 2015; at Troll A two new gas compressors were installed, the Åsgard subsea compression, the world’s first subsea gas compression plant, came on stream, and the world’s first subsea wet gas compressor is nearing completion at Gullfaks

 

Statoil made further portfolio adjustments to improve its NCS position. Statoil increased its share in the Alfa Sentral project, which straddles the border of the NCS and UK continental shelf (UKCS). Statoil’s equity share now stands at 24% in licence P312 on the UKCS and 62% in licence PL046 on the NCS (Statoil-operated); the two licenses together comprise the Alfa Sentral field. Statoil also farmed down in the Gudrun field. Statoil remains the operator of the field.

 

The target to reduce CO₂ emissions on the NCS was increased to 1.2 million tonnes by 2020, which is up 50% from the initial target of 800,000 tonnes. The initial target was set in 2008 and is expected to be reached in 2016.

 

Grow material and profitable international positions

International oil and gas production represents approximately 37% of Statoil’s equity production and now stands at 739 kboe/d. Statoil will continue to explore, develop, and produce oil and gas opportunities outside Norway to enhance Statoil’s upstream portfolio.

·          Exploration:  Statoil is an active international explorer for oil and gas. In the last year, Statoil participated in 18 completed exploration wells of which eight were discoveries. Statoil focused in Canada, Tanzania, Brazil, the UK and the US Gulf of Mexico. Statoil announced a gas discovery in Tanzania (Mdalasini-1). Statoil accessed new acreage in Canada, New Zealand, Indonesia, Mozambique, Russia, and the US Gulf of Mexico, and entered three new countries, Nicaragua, South Africa, and Uruguay. Government approval is pending for the newly acquired acreage in Mozambique, South Africa, and Uruguay. Statoil exited both our operated and non-operated licenses in the Chukchi Sea (Alaska). Statoil also closed its office in the Faroe Islands following the relinquishment of our exploration acreage

·          Development:  In Europe, the partner-operated Corrib gas field in Ireland came on stream at the end of 2015; meanwhile, Statoil postponed the Mariner field’s start-up date to 2018. In the US Gulf of Mexico, the partner-operated Heidelberg project entered its final stages in 2015 as it prepared for first oil in early 2016, meanwhile Big Foot was postponed due to technical challenges in the final project stage

·          Production:  Production has steadily increased from fields such as CLOV in Angola and Jack/St. Malo in the US Gulf of Mexico. In the US, further optimisation of the onshore portfolio targeting cost improvements has been on-going, including the reorganisation of some of the activities to extract greater synergies

 

Statoil made further portfolio adjustments to improve its international exploration portfolio. Statoil sees value in gaining operatorships, and in 2015 Statoil became the operator in BM-C-33 offshore Brazil, which contains the Pão de Açúcar, Seat, and Gávea discoveries. Statoil also completed an agreement to reduce Statoil’s average working interest in Statoil’s non-operated US southern Marcellus onshore asset from 29% to 23%. In another transaction, Statoil acquired an additional 13% interest in Statoil’s Eagle Ford joint venture and became its sole operator.

 

Pursue focused and value-adding mid- and downstream activities

The prime objective for Statoil’s mid- and downstream activities is to process and transport its oil and gas production (including the Norwegian State’s petroleum) competitively to premium markets, securing maximum value realisation. The priorities are:

·          High regularity in midstream operation and continuous improvement within HSE, efficiency and costs

·          Market Statoil’s equity production (crude oil, natural gas, related products) and the State’s Direct Financial Interest (SDFI) volumes for maximum value creation

·          Develop the Asset Backed Trading model across commodities

·          Maintain the position as a leading European gas supplier

·          A capital lean asset structure

 

Strategic focus is directed at optimising the value of Statoil’s flexible Norwegian gas production assets that supply Europe and Statoil’s midstream activities in North America, where Statoil’s onshore un-conventionals portfolio is progressing and where margin capture is important. Statoil achieved strong trading results across all commodities and robust refinery results through good margins, cost reductions and high availability.

 

Strategic progress in Statoil’s mid- and downstream portfolio has been made in 2015. Export pipelines for the Utsira High and the Norwegian Sea (Polarled) were installed. Statoil agreed to divest its 20% stake in the Trans Adriatic Pipeline AG in 2015 following earlier divestments in 2014.

 

Providing energy for a low carbon future

Statoil recognises that opportunities are increasingly available in producing low carbon energy. In 2015, Statoil created a new business area, New Energy Solutions, to further access, develop, and produce low carbon energy when and where it is deemed valuable.

·          Development:  In the 4^th quarter 2015, Statoil sanctioned Hywind Scotland Offshore Floating Test Park in Scotland; Statoil’s ownership share is 100%. The park will have a total installed capacity of 30 MW and planned production start-up is 2017. The Dudgeon Offshore Wind Park sanctioned in 2014 is progressing as planned towards start-up in 2017; Statoil’s ownership share is 35%. The park will have a total installed capacity of 402 MW. The Forewind consortium, comprising Statoil, Statkraft, RWE and SSE, all with a 25% owner stake, continues to mature projects and has received consent for four 1.2 GW projects in the Dogger Bank Area off the UK east coast

·          Production:  Statoil is a non-operating partner in the Scira consortium (40% owner stake) which produces electricity from the Sherringham Shoal wind park in the UK. The park has an installed capacity of 317 MW

 

Research, development, and deployment of technology to unlock opportunities and enhance value

Statoil believes that technology is a critical success factor in the current business environment. Statoil’s technology development activities aim to reduce field development, drilling and operating costs, and CO₂ and other greenhouse gas emissions. Statoil’s technology efforts focus on the following priority areas:

·          Business-critical technologies: Upstream technologies are prioritised, primarily in the areas of Exploration, Reservoir, Drilling and Well and Subsea production systems. Statoil’s main focus has been on cost reduction, for example further development of the steerable drilling liner system to reduce well construction costs

·          Strengthening Statoil’s licence to operate: Statoil’s commitment to sustainability continues. Statoil’s ongoing “Powering collaboration” agreement with GE aims to accelerate the development of more sustainable energy solutions by addressing CO₂ and methane emissions, water usage and energy optimisation of operations. Statoil is also addressing energy efficiency of operating assets by, e.g. implementing on-line water wash systems on gas turbines

·          Expanding Statoil’s capabilities: Statoil’s technical capabilities are expanding to meet the challenges of the New Energy Solutions business area for renewable and low carbon energy solutions. Technology development is conducted in-house, in collaboration with suppliers and through venture activities. A key technological focus area is finding more efficient ways of producing clean energy, particularly by reducing costs in the areas of construction and maintenance for both fixed and floating offshore wind applications

 

2.3 Group outlook

 

Statoil’s plans address the current environment while continuing to invest in high-quality projects. Statoil continues to reiterate its efforts and commitment to deliver on its priorities of high value creation, increased efficiency and competitive shareholder return.

 

·       Organic capital expenditures for 2016 (i.e. excluding acquisitions, capital leases and other investments with significant different cash flow pattern) are estimated at around USD 13 billion

·       Statoil intends to continue to mature the large portfolio of exploration assets and estimates a total exploration activity level of around USD 2 billion for 2016, excluding signature bonuses

·       Statoil aims to deliver efficiency improvements with pre-tax cash flow effects of around USD 2.5 billion annually from 2016

·       Statoil’s ambition is to keep the unit of production cost in the top quartile of Statoil`s peer group

·       For the period 2014 – 2017, organic production growth [7] is expected to come from new projects resulting in around 1% CAGR (Compound Annual Growth Rate) from a 2014 level rebased for divestments

·       The equity production for 2016 is estimated to be somewhat lower than the 2015 level [7]

·       Scheduled maintenance activity  is estimated to reduce quarterly production by approximately 25 mboe per day in the first quarter of 2016 of which the majority is liquids internationally. In total, the maintenance is estimated to reduce equity production by around 60 mboe per day for the full fiscal year 2016, which is higher than the 2015 impact

·       Indicative effects from Production Sharing Agreement (PSA-effect) and US royalties are estimated to be around 135 mboe per day in 2016 based on an oil price of USD 40 per barrel and 165 mboe per day based on an oil price of USD 70 per barrel [4]

·       Deferral of production to create future value, gas off-take, timing of new capacity coming on stream and operational regularity represent the most significant risks related to the production guidance

·       The board of directors proposes to the annual general meeting (AGM) maintaining a dividend of USD 0.2201 per share for the fourth quarter 2015 and to introduce a two-year scrip dividend programme for  eligible shareholders starting from the fourth quarter 2015  

·        With effect from first quarter of 2016, Statoil will change to USD as presentation currency

These forward-looking statements reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future. For further information see section 10 Forward-Looking Statements. 

 

3  Business overview

 

3.1 Our history

 

Statoil was formed in 1972 by a decision of the Norwegian parliament and listed on the stock exchanges in Oslo and New York in 2001.

 

Statoil was incorporated as a limited liability company under the name Den norske stats oljeselskap AS on 18 September 1972. As a company wholly owned by the Norwegian State, Statoil's role was to be the government's commercial instrument in the development of the oil and gas industry in Norway.

 

In 2001, the company became a public limited company listed on the Oslo and New York stock exchanges, and it changed its name to Statoil ASA.

 

Statoil has grown in parallel with the Norwegian oil and gas industry, which dates back to the late 1960s. Initially, Statoil’s operations were primarily focused on exploration, development and production of oil and gas on the Norwegian continental shelf (NCS), as a partner.

 

In the 1970s, Statoil commenced its own operations, made important discoveries and began oil refining operations, which have been of great importance to the further development of the NCS.

 

Statoil grew substantially in the 1980s through the development of large fields on the NCS (Statfjord, Gullfaks, Oseberg, Troll and others). Statoil also became a major player in the European gas market by securing large sales contracts for the development and operation of gas transport systems and terminals. During the same decade, Statoil was involved in manufacturing and marketing in Scandinavia and established a comprehensive network of service stations.

 

Since 2000, our business has grown as a result of substantial investments on the NCS and internationally. Our ability to fully realise the potential of the

NCS was strengthened through the merger with Hydro's oil and gas division on 1 October 2007.

 

In recent years, Statoil has utilised their expertise to design and manage operations in various environments in order to grow our upstream activities outside our traditional area of offshore production. This includes the development of heavy oil and shale gas projects.

 

In 2010, Statoil carried out an initial public offering of Statoil Fuel & Retail ASA on the Oslo Børs, partially divesting and reducing our interest in the business relating to service stations. In 2012, all of the remaining shares in Statoil Fuel & Retail ASA were divested.

 

Statoil also participates in projects that focus on other forms of energy, such as offshore wind and carbon capture and storage, in anticipation of the need to expand energy production, strengthen energy security and combat adverse climate change.

 

3.2 Our business

 

Statoil is a technology-driven energy company primarily engaged in oil and gas exploration and production activities.

 

Statoil ASA is a public limited liability company organised under the laws of Norway and subject to the provisions of the Norwegian Public Limited Liability Companies Act. The Norwegian State is the largest shareholder in Statoil ASA, with a direct ownership interest of 67%.

 

Statoil's head office is located in Stavanger, Norway. Statoil has business operations in more than 30 countries and employs about 21,600 employees worldwide.

 

Statoil is the leading operator on the Norwegian continental shelf (NCS) and also has substantial international activities. Statoil is present in several of the most important oil and gas provinces in the world. In 2015, 37% of Statoil's equity production came from international activities and the company also holds operatorships internationally.

 

Our access to crude oil in the form of equity, governmental and third party volumes makes Statoil a large net crude oil seller, and Statoil is the second-largest supplier of natural gas to the European market. Processing and refining are also part of our operations. Statoil is also participating in projects that focus on other forms of energy, such as offshore wind and carbon capture and storage, in anticipation of the need to expand energy production, strengthen energy security and combat adverse climate change.

 

Statoil's business address is Forusbeen 50, N-4035 Stavanger, Norway. Its telephone number is +47 51 99 00 00.

 

 

3.3 Our competitive position

 

There is intense competition in the oil and gas industry for customers, production licences, operatorships, capital and experienced human resources.

 

Statoil competes with large integrated oil and gas companies, as well as with independent and state-owned companies, for the acquisition of assets and licences for the exploration, development and production of oil and gas, and for the refining, marketing and trading of crude oil, natural gas and related products. Key factors affecting competition in the oil and gas industry are oil and gas supply and demand, exploration and production costs, global production levels, alternative fuels, and environmental and governmental regulations. In addition, Statoil competes to develop wind energy opportunities.

 

Statoil's ability to remain competitive will depend, among other things, on the company's management continuing to focus on reducing unit costs and improving efficiency, and maintaining long-term growth in reserves and production through continuing technological innovation. It will also depend on our ability to seize international opportunities in areas where our competitors may also be actively pursuing exploration and development opportunities. Statoil believes it is in a position to compete effectively in each of our business segments.

 

The information about Statoil's competitive position in the business overview and strategy, and operational review sections, is based on a number of sources. They include investment analyst reports, independent market studies, and our internal assessments of our market share based on publicly available information about the financial results and performance of market players.

 

Statoil has endeavoured to be accurate in our presentation of information based on other sources, but has not independently verified such information.

 

Improvement programmes

Statoil’s ambition to further reduce cost and improve efficiency was presented at the capital markets update (CMU) on 6 February 2015, targeting annual savings of USD 1.7 billion from 2016. At the CMU on 4 February 2016, Statoil announced that it will step up its efficiency programme by 50% with a goal to realise USD 2.5 billion in annual savings from 2016.

 

Improvement programmes are Statoil’s response to the industrial challenge characterised by reducing prices for our products, escalating cost and declining returns. More specifically, the ambition is to realise positive production effects and capex and operating cost savings to improve financial results and cash-flows.

 

3.4 Corporate structure

 

Statoil's operations are managed through the following business areas:

 

Development and Production Norway (DPN)

DPN comprises our upstream activities on the Norwegian continental shelf (NCS). DPN aims to continue its leading role and ensure maximum value creation on the NCS. Through excellent HSE and improved operational performance and cost, DPN strives to maintain and strengthen Statoil's position as a world- leading operator of producing offshore fields. DPN seeks to open new acreage and to mature improved oil recovery and exploration prospects. New and existing fields are primarily developed using an industrial approach, in which speed of delivery and cost improvements through standardisation and repeated use of proved solutions are key elements.

 

Development and Production International (DPI)

DPI comprises our worldwide upstream activities that are not included in the DPN and Development and Production USA (DPUSA) business areas. DPI's ambition is to build a large and profitable international production portfolio comprising activities ranging from accessing new opportunities to delivering on existing projects and managing a production portfolio. DPI endeavours to ensure the delivery of profitable projects in a range of complex technical and stakeholder environments, and it manages a broad non-operated production portfolio that will be complemented with operated positions.

 

Development and Production United States (DPUSA)

DPUSA comprises our upstream activities in the USA and Mexico. DPUSA's ambition is to develop a material and profitable position in the US and Mexico, including the deep water regions of the Gulf of Mexico and unconventional oil and gas in the US. In this connection, Statoil aims to further strengthen its capabilities in deep water and unconventional oil and gas operations.

 

Marketing, Midstream and Processing (MMP)

MMP comprises our marketing and trading of oil products and natural gas, transportation, processing and manufacturing, and the development of oil and gas value chains. MMP's ambition is to maximise value creation in Statoil's midstream, marketing and renewable energy business.

 

Technology, Projects and Drilling (TPD)

TPD's ambition is to provide safe, efficient and cost-competitive global well and project delivery, technological excellence, and research and development. Cost-competitive procurement is an important contributory factor, although group-wide procurement services are also expected to help to drive costs in the group down.

 

 

 

Exploration (EXP)

EXP's ambition is to position Statoil as one of the leading global exploration companies. This is achieved through accessing high potential new acreage in priority basins, globally prioritising and drilling more significant wells in growth and frontier basins, delivering near-field exploration on the NCS and other select areas, and achieving step-change improvements in performance.

 

New Energy Solutions (NES)

NES reflects Statoil’s aspirations to gradually complement its oil and gas portfolio with profitable renewable energy and other low-carbon energy solutions. NES is responsible for wind parks, carbon capture and storage as well as other renewable energy and low-carbon energy solutions.

 

Global Strategy and Business Development (GSB)

GSB sets the corporate strategy, business development and merger and acquisition (M&A) activities for Statoil. The ambition of the GSB business area is to closely link corporate strategy, business development and M&A activities to actively drive Statoil's corporate development.

 

Reporting segments

Statoil reports its business in the following reporting segments: Development and Production Norway (DPN); Development and Production International

(DPI), which combines the DPI and DPUSA business areas; Marketing, Midstream and Processing (MMP); and Other.

 

The Other reporting segment includes activities in New Energy Solutions (NES), Technology, Projects and Drilling (TPD), Global Strategy and Business Development (GSB) and Corporate staffs and support functions. Activities relating to the Exploration (EXP) business area are allocated to, and presented in, the respective development and production segments.

 

Presentation

In the following sections, the operations of each reporting segment are presented. Underlying activities or business clusters are presented according to how the reporting segment organises its operations. The Exploration business area's activities, which include group discoveries and the appraisal of new exploration resources, are presented as part of the various development and production reporting segments (Development and Production Norway, and Development and Production International).

 

As required by the SEC, Statoil prepares its disclosures about oil and gas reserves and certain other supplementary oil and gas disclosures based on geographical areas. The geographical areas are defined by country and continent. They consist of Norway, Eurasia excluding Norway, Africa, and the Americas.

 

See note 3 Segments  in the Consolidated financial statement for more details.

 

3.5 Development and Production Norway (DPN)

 

3.5.1 DPN overview

 

Development and Production Norway (DPN) is responsible for field development and operational activities on the Norwegian continental shelf (NCS).

Statoil's equity and entitlement production on the NCS was 1,232 mboe per day in 2015. That was about 68% of Statoil's total entitlement production and 62.5% of Statoil's equity production.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Key events and portfolio developments in 2015:

·          In January 2015, Statoil announced the start-up of production at the Valemon oil and gas field in the North Sea

·          Statoil announced production start up on fast track projects at the Oseberg Delta in February, Gullfaks Sør Olje in July and Smørbukk Sør Extension in September

·          In November the start up of production at the Edvard Grieg field was announced by Lundin

·          The major redevelopment projects Åsgard Subsea compression and two new compressors on the Troll A platform have started up

·          A total of seven turnarounds were planned to be performed during 2015. Four turnarounds were carried out, and three turnarounds were deferred from 2015 to 2016 to coordinate with other activities due to reduce production losses and reduce costs

·          Plan for Development and Operations (PDO) for the Johan Sverdrup field and Gullfaks Rimfaksdalen Fast track project were approved by the Ministry of Petroleum and Energy (MPE) and the PDO for Oseberg Vestflanken 2 was submitted to the MPE

·          An extensive exploration drilling program in 2015 resulted in 21 completed wells, of which 10 were discoveries. A total of 16 wells were Statoil operated

·          Statoil has delivered an extensive application for the 23^rd concession round and has been awarded interest in 24 licenses on the NCS in the Awards in Predefined Areas (APA) 2015, 13 of those as operator and 11 as partner

·          In December Statoil announced that it farmed down to Repsol a 15% interest in the Gudrun field. Statoil remains as operator and largest equity holder with a 36% interest

 

The profitability of our industry continues to be challenged. Statoil’s response to the industrial challenge characterised by high costs and declining returns is addressed in the section 2 Strategy and market overview.    

  

 

3.5.2 Fields in production on the NCS

 

Statoil’s entitlement production at NCS was about 68% of Statoil’s total entitlement production in 2015.

 

The following table shows DPN's average daily entitlement production of oil, including NGL and condensates, and natural gas for the years ending 31 December 2015, 2014 and 2013. Field areas are groups of fields operated as a single entity.

 

The following table shows the NCS production by fields and field areas in which Statoil was participating as of 31 December 2015.

 

 

 

  

 

3.5.2.1 Operations North

 

The main producing fields in the Operations North area are Snøhvit and Norne.

 

The Norwegian Sea region is characterised by petroleum reserves located at water depths between 340 and 380 metres. In the Barents Sea the petroleum reserves are located at water depths between 310 and 340 meters. The Gulf Stream keeps the sea free of ice all year round, but winter storms can make surface installations difficult to operate.

 

Snøhvit was the first field developed in the Barents Sea. It is one of the first major developments using onshore production facilities. All offshore installations are subsea. The natural gas is transported to shore and then processed at our Liquefied Natural Gas (LNG) plant on Melkøya. The LNG are shipped to customers in Europe, Asia, North and South America in tankers. The CO₂ in the feed-gas from Snøhvit and Albatross is removed due to freezing constraints in the process system. To reduce carbon dioxide emissions to the air the removed CO₂ is liquefied, transported through a pipeline, and then injected into a storage reservoir in Snøhvit. The LNG plant has produced according to plan in 2015, with high production efficiency, improved HSE results and enhanced cost efficiency. As of 1 January 2016 responsibility for operation of Snøhvit onshore facilities is transferred from DPN to MMP.

 

Norne is an oil field in the Norwegian Sea. The field has been developed using a floating production, storage and offloading vessel (FPSO) connected to subsea templates. Alve, Marulk, Urd and Skuld are tie-in fields connected to the Norne FPSO.

 

3.5.2.2 Operations Mid-Norway

 

The main producing fields in the Operations Mid-Norway area are Åsgard, Kristin, Tyrihans and Heidrun.

 

Operation Mid-Norway operates in a mature part of the Norwegian Sea, and is a significant contributor to Statoil’s equity production. Main focus is to capitalise existing fields through profitable realisation of increased oil recovery and successful implementation of new developments. There is still exploration potential in the area and a targeted exploration effort is in execution.

 

The Åsgard field includes the Åsgard A production and storage ship for oil, the Åsgard B semi-submersible floating production platform for gas, and the Åsgard C storage vessel for condensate. In September 2015 Statoil started the world first subsea gas compressor on Åsgard. The compressor increases the Åsgard recovery rate from 67% to 87% thereby extending the reservoirs’ productive lives. Mikkel and Morvin are tie ins to Åsgard.

 

Tyrihans is a subsea field with five templates. The well stream of oil and gas is tied back to Kristin for processing. Tyrihans receives seawater injection from Kristin and gas injection from Åsgard B.

 

Kristin is a gas and condensate field. The Kristin development is the first high-temperature/high-pressure (HTHP) field developed with subsea installations. The pressure and temperature in the reservoir are among the highest of all developed fields on the NCS.

 

Heidrun is developed with a floating concrete tension leg platform. The oil is transferred to the floating storage unit, Heidrun B, operated from June 2015. 

 

The Njord field is located in the Norwegian Sea and the field has been developed with a floating steel platform unit, Njord A, with both drilling and processing facilities. The subsea field Hyme is tied back to Njord A.

As a result of structural integrity issues Njord A was temporarily shut down and extensive reinforcement work was completed through a long turnaround period from Sept 2013 to July 2014. Since July 2014 conditional monitoring and precautionary evacuation in forecasted bad weather conditions have been applied. In addition there is no drilling activity. The Project “Njord Future” is established to secure long term production for both the Njord and Hyme fields and to act as a tie-in host candidate for discoveries in the area.

 

3.5.2.3 Operations West

 

The main producing fields in the Operations West area are Troll, Oseberg, Gullfaks, Kvitebjørn, Visund and Grane

 

Operation West produces approximately half of Statoil’s equity production in Norway. Its main focus is prolonging and increasing production through increased oil recovery, exploration and new field developments.

 

Troll is the largest gas field on the NCS and a major oil field. The Troll field is split into three hydrocarbon-bearing regions connected to three platforms: Troll A, B and C. The Troll gas is mainly exported and produced at the Troll A platform, while oil is mainly produced at Troll B and C. Fram and Fram H Nord are tie-ins to Troll C.

 

In October 2015 Troll A finalised the third and fourth pre-compressor project as described in the original PDO for the Troll field. The purpose of the project is to increase gas production by installing two extra pre-compressors on the Troll A platform.

 

The Oseberg area includes the Oseberg Field Centre, Oseberg C, Oseberg East and Oseberg South production platforms. Oil and gas from the satellites are transported in pipelines to the Oseberg Field Centre for processing and transportation.

 

The Delta2 facilities project on Oseberg Field Center was completed in 2015. Drilling operations related to the project have been on-going throughout 2015 and were finalised in January 2016. The Vestflanken2 project at Oseberg Field Center was sanctioned December 2015 with drilling to be performed by the Cat-J rig on the new unmanned wellhead platform, both under construction, with drilling expected to start third quarter in 2017. The Tender Support Vessel (TSV) project at Oseberg Øst is expected to commence drilling support operations in 2016.

 

Gullfaks has been developed with three large concrete production platforms. Since production started on Gullfaks in 1986, five satellite fields have been developed with subsea wells that are remotely controlled from the Gullfaks A and C platforms.

 

Drilling of the new Gullfaks South Increased Oil Recovery (GSO IOR) project wells is ongoing. Operations on the satellites will continue with a mobile rig until September 2016 and plan for development and operation for Shetland/Lista was delivered in second quarter of 2015.

 

The Gullfaks Rimfaksdalen (PDO) was submitted in 2014 and production will start up in the fourth quarter of 2016. Drilling of wells was completed in 2015. The projects Gullfaks B Drilling Upgrade and Gullfaks South IOR both started up in 2015.

   

Kvitebjørn  is a gas and condensate field. The field is developed with an integrated accommodation, drilling and processing facility with a steel jacket.

 

The Valemon field is a gas and condensate field between Kvitebjørn and Gullfaks South. Valemon is built as a normally not manned, fixed steel platform with separation facilities for gas, condensate and water. The condensate is piped to Kvitebjørn for stabilisation and from there to the Mongstad refinery near Bergen.  The production started in January 2015.

 

Visund is an oil and gas field development that includes floating drilling, production and living quarter units and two subsea templates, in the northern and southern parts of the field.

 

Grane is Statoil's largest producing heavy oil field. The Svalin field is a tie-in to Grane platform.

 

The Heimdal platforms are a hub for the processing and distribution of gas to the European gas markets. The hub consists of an integrated steel platform and a riser platform. During 2015 Heimdal has plugged and abandoned its production wells in the main reservoir. Heimdal will start production in 2016 from one new well drilled from the modular rig which was temporarily installed for plugging and abandonment activity.

 

3.5.2.4 Operations South

 

The main producing fields in Operations South are Sleipner, Gudrun, Statfjord and Snorre.

 

Operation South represents a mature oil and gas province. However, it still remains a significant contributor to Statoil’s equity production and new fields are under development in the area. Main focus in the area is to capitalise on existing fields through profitable realisation of increased oil potential and successful implementation of new developments.

 

Sleipner consists of the Sleipner East, Gungne and Sleipner West gas and condensate fields. The gas from Sleipner has a high level of CO. This is extracted at the field and re-injected into a sand layer beneath the seabed to reduce carbon dioxide emissions to the air. Sleipner also processes gas, condensate and oil from Gudrun, Volve and Sigyn. The Gina Krog field, currently under development, will also be tied back to Sleipner.

 

The Gudrun field is a separate steel jacket-based process platform for separation of oil and gas, with separate pipelines transporting gas and partly stabilised oil from Gudrun to Sleipner.

 

Statfjord has been developed using three fully integrated platforms supported by gravity-based structures with concrete storage cells and an offshore loading system. Statfjord North, Statfjord Øst and Sygna are satellite fields have all been developed using subsea templates tied back to Statfjord C.

 

The Snorre field has two floating platforms and one subsea production system connected to the Snorre A platform. In addition, the satellite fields Tordis and Vigdis are part of Snorre business unit and are tied back to Gullfaks C and Snorre A, respectively.

  

 

3.5.2.5 Partner-operated fields

 

Partner-operated fields account for approximately 11% of our total oil and gas production on the NCS. The main producing fields are Ormen Lange, Skarv and Ekofisk.

 

Statoil's partner operated fields NCS portfolio is organised under Operations South.

 

Ormen Lange operated by Shell, is a deepwater gas field in the Norwegian Sea. The well stream is transported to an onshore processing and export plant at Nyhamna.

 

Skarv is an oil and gas field located in the Norwegian Sea, with BP as operator. The field development includes a floating production, storage and offloading vessel (FPSO) and five subsea multi-well installations.

 

Ekofisk is operated by ConocoPhillips. It consists of the Ekofisk, Eldfisk and Embla fields, and Tor. The Eldfisk II project delivered a new PDQ platform early 2015 that will serve as Eldfisk field center.

 

Edvard Grieg  is an oil field located in the Utsira High Area. The field development includes a fixed steel jacket with processing and export facilities. Edvard Grieg is operated by Lundin. Production started on 28 November 2015 according to plan. Two wells were ready at start-up. Drilling will continue and a total of 10 production wells and four injection wells are planned.

 

3.5.3 Exploration on the NCS

 

Continued high exploration activity on the NCS

 

An extensive drilling program in 2015 resulted in 21 completed wells, of which 10 were discoveries. A total of 16 wells were Statoil operated.

 

Statoil has delivered an application for the 23^rd concession round on the NCS. The round covers 57 blocks and parts of blocks, with three in the Norwegian Sea and 54 in the Barents Sea. South-East Barents Sea is the first new exploration acreage area opened on the NCS since 1994. Statoil and 15 other companies cooperate in the Barents Sea Exploration Collaboration (BaSEC) project to find common solutions for exploration operations in the Barents Sea and to ensure cost-effectiveness and good safety standards.

 

Statoil has been awarded interest in 24 licences in the Awards in Predefined Areas (APA) round 2015 on the NCS, 13 of those as operator and 11 as partner. Statoil has been awarded new licences in all three NCS provinces – North Sea, Norwegian Sea and the Barents Sea.

 

In general, Statoil’s exploration strategy on the NCS is reflected in its diverse exploration portfolio, which ranges from frontier drilling to infra-structure led exploration close to existing infrastructure.

 

The table below shows the exploration and development wells drilled on the NCS in the last three years.

 

Potential producing areas

In addition to producing areas, Statoil operates a significant number of exploration licences. Exploration takes place in undeveloped frontier areas as well as near existing infrastructure and producing fields.

 

North Sea

In the North Sea, Statoil participated in 14 exploration wells. Statoil operated ten of the exploration wells with seven discoveries.

 

Norwegian Sea

In the Norwegian Sea, Statoil participated in six exploration wells. Statoil operated five of the exploration wells with three discoveries. 

 

Barents Sea

No Statoil operated wells in 2015. One partner operated well was completed in 2015.

 

3.5.4 Fields under development on the NCS

 

The main sanctioned development projects on the NCS.

 

The table below shows some key figures as of 31 December 2015 for Statoil’s major development projects on the NCS.

 

 

Johan Sverdrup is an oil discovery in the southern part of the North Sea, approximately 140 km west of Stavanger. A plan for development and operation was submitted in February 2015 and approved by the Norwegian authorities in August 2015. The Phase 1 of the development will consist of 35 production and water injection wells and a field center with four platforms: A living quarter platform, a wellhead platform with permanent drilling facility, a processing platform and a riser and utility platform. The crude oil will be exported to Mongstad through a 274 km long dedicated pipeline, and the gas will be exported to the gas processing facility at Kårstø through a 156 km long pipeline via a subsea connection to the Statpipe pipeline. The expected production start-up is in the fourth quarter of 2019.

 

Aasta Hansteen  is a deep water gas discovery in the Norwegian Sea. The development concept includes three subsea templates tied in to a floating processing unit with gas export through a new pipeline, Polarled, to Nyhamna and further exportation through the Langeled pipeline. The Aasta Hansteen processing unit can also serve as a hub for other potential discoveries in the area. Expected production start-up is in 2018.

 

Gina Krog  is an oil and gas discovery in the North Sea approximately 30 kilometres north of the Sleipner field. The field development concept includes a steel-jacket platform. Oil will be exported via offshore loading from a floating storage unit. Due to the high condensate content, the rich gas will be exported via Sleipner, where it will be further processed. The development concept also includes gas injection in order to maximise the recovery factor for the field. The development concept includes a total of 15 wells. Expected production start-up is in 2017.

 

Ivar Aasen is an oil and gas field located in the Utsira High Area. The development includes a fixed steel jacket with partial processing and living quarters tied in as a satellite to Edvard Grieg for further processing and export. The Ivar Aasen development is operated by Det norske, The operator expects production start-up in the fourth quarter of 2016.

 

Goliat is the first oil field to be developed in the Barents Sea. The field is being developed by means of subsea wells tied back to a circular floating production, storage and offloading vessel (FPSO). The oil will be offloaded to shuttle tankers. The Goliat development is operated by Eni who expects production start-up during first quarter of 2016.

 

Martin Linge is an oil and gas field, operated by Total, near the British sector in the North Sea. The reservoir is complex with gas under high pressure and high temperatures. The development includes a platform as a fixed steel jacket with processing and export facilities. Electrical power will be supplied from Kollsnes. The operator expects production start-up in 2018.

 

Redevelopment on the NCS - Improved oil recovery (IOR)

In 2015 Statoil started the world’s first subsea gas compression plant at the Åsgard field. Processing on the seabed, particularly gas compression, is important for developing seabed solutions for areas of deeper water and in colder and more challenging areas. Åsgard’s subsea compression, the world’s first subsea gas compression plant, is one of Statoil's most demanding technology projects. The compressors will increase recovery from the Midgard reservoir on Åsgard from 67 percent to 87 percent, and from the Mikkel reservoir from 59 percent to 84 percent, extending the operational life of the fields up to 2032 and contributing to significant reduction in energy consumption and CO₂ emissions over the fields’ lifetimes.

 

The Gullfaks subsea compression project the second largest subsea gas compression project being developed by Statoil on the NCS. Subsea gas compression will have a significant impact on the Gullfaks field as this technology, combined with conventional low-pressure production, is expected to lift the recovery rate from the Gullfaks South Brent reservoir from 62% to 74%.

 

The Smørbukk South Extension project, in the Åsgard field, is a world class project production from tight formations previously regarded as infeasible. Production began in September 2015 through the combination of wells with long well sections and “fishbones”, a new completion technology implemented for the first time on the NCS, and further utilisation of existing infrastructure at Åsgard.

 

Troll A field’s two new topside compressors started operating in October 2015. Installation of these compressors is an important step to achieve the Troll field's long-term production profile, which now extends to 2063. They are operated with power from shore, which reduces the field’s CO₂ emissions significantly.

 

The  Gullfaks South Oil (GSO) project started production in July 2015 and will increase recovery from the Gullfaks area. It includes two subsea templates, four production wells, two gas injectors, a gas injection pipeline and umbilicals and power cables for pipeline heating. The project utilise spare processing capacity and will extend the Gullfaks A platform life beyond 2030.

 

The Gullfaks B lifetime extension project aims at extending the drilling program on the Gullfaks B platform until 2032. Operation started on August 2015. Many of the future wells in Gullfaks B are water injection wells that will help maintain production from all three of the platforms in the field through increased pressure support in the reservoir. The drilling upgrade also provides the opportunity to connect to smaller producers from the surrounding area.

 

The Ormen Lange onshore compression project being executed as part of the overall expansion of the Nyhamna facility to handle third-party gas entering the plant through the new Polarled pipeline. The two 37 MW onshore compressors are scheduled for start-up in July 2017.

 

These projects are all examples of Statoil’s efforts to maximise recovery from existing fields. They have also opened opportunities for technology application to realise volumes from other fields with similar conditions.

 

3.5.5 Decommissioning on the NCS

 

Under the Petroleum Act, the Norwegian government has imposed strict procedures for removal and disposal of offshore oil and gas installations. The Convention for the Protection of the Marine Environment of the Northeast Atlantic (OSPAR) stipulates similar procedures.

 

Glitne ceased production in February 2013 and decommissioning of the field has been ongoing 2013 - 2015. Permanent plugging and abandonment of the seven wells completed in October 2014. All facilities/equipment were removed from the field in 2015. Safety zones in the area have been repealed and national maps updated.

 

Huldra ceased production in September 2014, after 13 years in production. Permanent plugging and abandonment of six wells is planned for 2016 and the plan is that the Huldra topside facilities will be removed in 2019.

 

Yttergryta is a subsea field with one production well that ceased production in 2013. Permanent plugging of the well was completed early in 2015.

 

On Heimdal a modular drilling rig has been  successfully installed in order to plug and abandon all 12 wells at the Heimdal main reservoir. The plug and abandonment project started in the fourth quarter 2014, and is scheduled to be finalised by second quarter 2016.

 

During 2015 there were permanent plugging and abandonment operations at Statfjord Øst, Statfjord A, Sleipner and Tordis. In addition Åsgard decommissioned part of the Midgard flowline loop in 2015.

 

For further information about decommissioning see note 2 Significant accounting policies to the Consolidated financial statements.

 

3.6 Development and Production International (DPI)

 

3.6.1 DPI overview

 

Statoil is present in several of the most important oil and gas provinces in the world.

 

Development and Production International (DPI) is responsible for all development and production of oil and gas outside the Norwegian continental shelf (NCS).

 

In 2015, DPI was engaged in production in 11 countries: Algeria, Angola, Azerbaijan, Brazil, Canada, Ireland, Nigeria, Russia, the UK, the US, and Venezuela. DPI produced 37% of Statoil's total equity production of oil and gas in 2015.   

 

As of 31 December 2015, Statoil has exploration licenses in North America (Canada and US), South America and sub-Saharan Africa (Angola, Brazil, Colombia, Mozambique, Nicaragua, Suriname, South Africa and Tanzania), North Africa (Algeria and Libya), Europe and Asia (Azerbaijan, Greenland, Indonesia, Myanmar, Russia and the UK) as well as Oceania (Australia and New Zealand). The main development projects in which DPI is involved are in Brazil, Canada, the UK, and the US.

 

Statoil also has representative offices in Kazakhstan, Mexico and United Arab Emirates.

Statoil closed its office in Iran in 2013 but has residual payment obligations for tax and social security under legacy contracts in Iran. These will be dealt with in accordance with all applicable sanctions. See section 5.1.1 Risks related to our business for information regarding sanctions towards Iran.

 

The map shows Statoil’s international producing countries and additional countries where Statoil has discoveries and/or exploration acreage.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Key events and portfolio developments in 2015:

·          Eight wells (exploration and appraisal) were announced as discoveries in 2015, including the Piri 2, Tangawizi 2 and Mdalasini (Statoil-operated) discoveries in Tanzania

·          Statoil accessed new acreage in Lampyrus in Russia, Mozambique, Nicaragua, Flemish Pass basin and Nova Scotia in East Coast Canada and South Africa

·          In January, a transaction with Southwestern Energy was closed. The agreement reduced Statoil’s working interest in the non-operated US southern Marcellus  onshore asset from 29% to 23%

·          Delay of Big Foot development first oil in the US Gulf of Mexico. The operator Chevron expects first oil in 2018. Initial plans called for production to start in late 2015, however, installation was halted and the tension leg plarform (TLP) moved to sheltered waters following damage to subsea installation tendons in late May 2015

·          In April, the Kizomba Satellites Phase 2 project in Block 15 offshore Angola started production

·          In April, Statoil completed its sale of its remaining 15.5% interest in Shah Deniz and the South Caucasus Pipeline (SCP) to the Malaysian oil and gas company PETRONAS. The effective date was 1 January 2014

·          In August, the Peregrino  field offshore Brazil passed a significant milestone with 100 million barrels of oil produced since production started in April 2011

·          On 30 December, the Shell operated Corrib gas field in Ireland started production

·          In December, Statoil completed the sale of its 20% interest in Trans Adriatic Pipeline AG (TAP) to the Italian gas infrastructure company Snam. TAP is an 882 km-long section of the Southern Gas Corridor, linking Shah Deniz Stage 2 to gas markets in Europe

·          In December, transactions with Repsol were announced. As a result of these transactions, Statoil’s working interest in the US Eagle Ford increased from 50% to 63% and Statoil took full operatorship. In addition, Statoil will assume operatorship of the BM-C-33  licence in Brazil’s Campos basin and acquire a 31% equity share in the UK licence for Alfa Sentral, a field which spans the UK-Norway maritime border. The transactions for BM-C-33 and Alfa Sentral are pending approval from relevant government authorities

·          In February 2016, the In Salah Gas joint venture announced the start- up of operations at the In Salah Southern Fields project in Algeria

·          Significant impairment losses on assets and oil and gas prospects and signature bonuses were recognised in 2015, see section 4.1.5 DPI profit and loss analysis for further details

 

The profitability of our industry continues to be challenged. Statoil’s response to the industrial challenge characterised by high costs and declining returns is addressed in the section 2 Strategy and market overview.    

 

3.6.2 International production

 

Statoil's entitlement production outside Norway was about 32% of Statoil's total entitlement production in 2015.

 

The following table shows DPI's average daily entitlement production of liquids and natural gas for the years ending 31 December 2015, 2014 and 2013. Entitlement production figures are after deductions for production sharing and profit sharing. For US assets entitlement production are expressed net of royalty interests. For all other countries royalties paid in-cash are included in entitlement production and royalties payable in-kind are excluded.

 

The table below provides information about the fields that contributed to production in 2015

 

Producing fields during calendar year 2015