NYC-based PIRA Energy Group reports that Long haul trucking has been losing market share to rail since 2002. In the U.S., there was another record U.S. commercial stock level. In Japan, crude stocks and finished product stocks built. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Lower U.S. Diesel Prices Should Limit Further Long Haul Trucking Loses to Rail
Long haul trucking has been losing market share to rail since 2002 when diesel prices averaged $1.75/gallon. This note estimates that diesel prices no higher than $3.25/gallon should stem any further erosion of long haul trucking's competitive position through 2016 even though momentum has set in for rail to displace long haul and possibly medium haul trucking on a long term basis.

Another Week, Another Record U.S. Commercial Stock Level
Total commercial stocks built last week to yet another new record high. With a small draw this week last year, the year-over-year surplus widened again. Crude built again this week. The four major refined products drew and all other oils were flat. The crude stock surplus versus last year stands at 82.7 million barrels. The four major refined products surplus widened to 30.3 million barrels, and the all other oils surplus widened to 45.8 million barrels above last year. Of that "other oil" excess, 43.7 million barrels is in propane & other NGL stocks.

Japanese Crude Stocks and Finished Product Stocks Build, Runs Ease
Crude runs eased again as maintenance continues to pick up its pace. Crude stocks built slightly due to a higher import figure. Finished product stocks also built, notably gasoil, naphtha, and fuel oil, though there was a strong end-of-season draw on kerosene. The indicative refining margin remained strong.

Tight Oil Operator Review
Weak oil prices dominated fourth quarter results and the outlook for 2015. The effect of falling prices rippled throughout the production chain, both on an operational and a financial level. For the companies covered, capex guidance for 2015 was 35% lower than 2014 capex on average. Simultaneously, technology and productivity improvements continued in 4Q14, and are expected to accelerate in 2015. The consensus seems to be a target of a 10% reduction in costs from efficiency gains, and a further 20% cost reduction from service price deflation. PIRA expects U.S. shale oil production to flatten out and slightly decline in 2Q15.

LPG Prices Drop with Season Change
LPG prices fell as U.S. inventories rose for the first time in 14 weeks. April propane futures for Mont Belvieu delivery fell to 50¢/gal, a 6.6% decrease on the week. Butane also lost ground as seasonal gasoline blending demand evaporates. LPG prices should remain under pressure as demand is set to continue decreasing as winter conditions continue to fade.

Manufacture of Ethanol- blended gasoline Jumps
Ethanol-blended gasoline manufacture soared to a 12-week high 8,676 MB/D the week ending March 13, from 8,434 MB/D in the previous week. Inventories declined for the third consecutive week, dropping 353 thousand barrels to 20.8 million barrels.

The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA's current analysis of energy markets around the world as well as the key economic and political factors driving those markets.

Chevron Corporation (NYSE: CVX) executives, at the company's annual security analyst meeting in New York, expressed confidence in the long-term energy business and highlighted its growth outlook through 2017. At the same time, company executives outlined near-term actions to address the recent decline in commodity prices.

"The fundamentals of the oil and gas business remain attractive for our company and investors, as our products are vital to a growing world economy," said John Watson, Chevron's chairman and CEO. Watson added, "We are well-positioned to manage through the recent drop in commodity prices and are taking several responsive actions, including curtailing capital spending and lowering costs."

"Over the next few years, we expect to deliver significant cash flow growth as projects currently under construction come online. Our intention is to demonstrate performance that will allow our 27-year history of successive increases in our annual dividend payout to continue," Watson added.
George Kirkland, vice chairman and executive vice president, upstream, reviewed Chevron's upstream portfolio, strategies, and historical performance, including the company's consistent exploration and resource capture success over the past decade. He also highlighted the upstream segment's superior financial performance relative to industry peers, as well as its leading competitive cost structure.

"This was the fifth consecutive year we have led the integrated peer group on earnings per barrel," Kirkland said. "Our base business is performing exceptionally well and is profitable, even in a lower-price environment. Our large, diverse resource base allows us to be very responsive to market conditions, with flexibility to select only the most attractive opportunities to move forward."

Jay Johnson, senior vice president, upstream, provided an overview of the specific actions being taken to manage capital outlays, lower costs and improve operating efficiencies, all of which will contribute to improving upstream cash flow. He also provided a comprehensive update on Chevron's deep queue of projects and other future investment opportunities, emphasizing their strong cash and value generation potential.

"We continue to make steady progress on our LNG and deepwater developments, and will continue to ramp-up production from our shale and tight assets, particularly from our very attractive Permian Basin acreage position," Johnson said. "We expect to achieve 20 percent production growth by 2017, a rate which is simply unmatched by our industry peers. More importantly, our new production is expected to have considerably higher margins than in our existing portfolio."

Pat Yarrington, vice president and chief financial officer, and Mike Wirth, executive vice president, Downstream and Chemicals, also participated during the question and answer session of the meeting, following the main presentations. Presentations and a full transcript of the meeting are available on the Investor Relations website at www.chevron.com.

Governments' responses to low oil prices will have a significant effect on supply dynamics for years to come, depending on whether fiscal regimes are adjusted to provide a landscape in which companies can make big development decisions, says an analyst with research and consulting firm Globaldata.

According to Will Scargill, Globaldata's Upstream Fiscal Analyst, relatively low costs and the design of fiscal regimes in a number of countries should mitigate the impact of the recent price drop in most mature basins. However, the threat to Exploration and Production (E&P) companies' bottom lines means that improved recovery in high-cost mature basins is compromised, new developments in growth areas are being put on hold, and unconventional development is slowing.

Scargill comments: "Several governments have taken positive steps to adapt to lower prices in recent months, with Argentina's measures especially improving project economics. Argentina has reduced the investment threshold for the Investment Promotion Scheme for Hydrocarbon Production and has decreased the rate of export duty, for when oil prices are below $80 per barrel (bbl), to 10–13% from 45%, meaning fields should remain profitable at $50/bbl.

"The impact of low prices in the short to medium term is likely to be felt most keenly by governments in countries that rely on hydrocarbon revenues, such as Russia and Venezuela, while the effect on supply should be relatively limited. The exception to this is in the North Sea, where high costs mean that tax cuts are required if lasting effects on the sector are to be avoided."

However, the analyst notes that to enable companies to make large investment decisions in growth areas and frontier basins, governments should offer a fiscal regime that responds to prevailing price given the cyclical nature of oil prices.

Scargill continues: "Brazil's pre-salt resources could add millions of barrels per day to supply by the 2020s, but this is contingent on E&P firms feeling confident enough to commit billions of dollars to development now.

"Additionally, deepwater discoveries in Mexico's Perdido Fold Belt have generated significant interest, and with an anticipated breakeven price between $41-65/bbl for new licenses, including the additional royalty, the commercial viability of developing these areas will depend on the final fiscal regime design."

Cal Dive International, Inc. (OTC: CDVI) ("Cal Dive", or the "Company") announced today that it and its U.S. subsidiaries have filed simultaneous voluntary petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. The Company's foreign subsidiaries have not sought bankruptcy protection and will continue to operate outside of any reorganization proceedings. The Company and its U.S. subsidiaries will continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court.

Through the Chapter 11 process, the Company will sell non-core assets and intends to reorganize or sell as a going concern its core subsea contracting business. During the reorganization process, the Company and its subsidiaries will continue to operate in the ordinary course, including completing the existing construction projects in Mexico for Pemex, and other ongoing diving and offshore construction projects for its customers worldwide. The Company anticipates no disruption in its services and its focus remains on delivering excellent project execution and safety performance for its customers.

The Company has received a commitment for up to $120.0 million in debtor-in-possession (DIP) financing from its current first lien lenders led by Bank of America, which will immediately provide additional liquidity to continue its operations during the Chapter 11 process. The DIP financing, which is subject to Court approval, will provide adequate funds for post-petition supplier and employee obligations, as well as the Company's ongoing operations needs during the Chapter 11 process.

Commenting on the filing, Cal Dive's Chairman, President and Chief Executive Officer, Quinn Hébert, stated, "Our business has experienced several adverse events that were beyond our control, and with our current capital structure, we are no longer able to financially withstand the industry downturn. In 2014, our financial performance suffered primarily as a result of delays caused by the suspension of two large projects, weather disruptions and delays caused by other contractors. Because these contracts contain milestone billing provisions, these delays and suspensions impeded our ability to invoice and collect payment for work performed, significantly impairing our liquidity which had already been reduced by declining industry conditions over the past several years. Our efforts to negotiate additional financing to fund business activities and pursue identified strategic alternatives were further impeded when oil prices plummeted, creating an additional, unexpected obstacle to our restructuring efforts. After considering several alternatives, we felt the Chapter 11 process was the most effective way to maximize value for our stakeholders."

Mr. Hébert continued, "We are committed to meeting the challenges of our industry head on. By availing ourselves of the Chapter 11 process, we can achieve an orderly restructuring for our business that has consistently produced competitive results under a more favorable capital structure."

More information on the Company's Chapter 11 process, including access to Court documents and other general information about the Chapter 11 cases, is available at www.caldive

We're not competing with fixed foundations, we're just creating the future. And that future's not that far away." CEO, Principle Power, EWEA 2015

Several floating wind turbines have been installed in recent years, with operational turbines in Norway, Japan and Portugal. Floating turbines have several benefits over their conventional counter-parts – firstly, they are more economically efficient, as onshore assembly and the ability to tow them into place reduces the need for costly heavy-lift vessels or specialized WTIVs. Secondly, floating turbines can be installed in deeper water (often further offshore) alleviating concerns of visibility from the coast. Thirdly, greater offshore distance increases wind exposure, resulting in comparatively higher electricity generation. We ask, however, whether floating wind turbines will be utilized globally as governments seek to meet renewable energy quotas?

Successful installations provide hope to those championing floating wind turbines. The WindFloat project in Portugal, is a particularly interesting example – currently supporting a 2MW turbine, 6km from shore. WindFloat refers to the floating support structure, which allows wind turbines to be installed in water depths exceeding 40m. The structure comprises three columns, each is fitted with water entrapment plates at the base, resulting in improved motion performance and allowing the use of conventional wind turbines atop the structure. WindFloat has been operational for three years and by end-2014 had delivered 12GWh of renewable electricity to the Portuguese grid, with no issues to date. Other successful projects include Hywind and Sway prototype projects in Norway, and a number of pilot projects in Japan.

DW's Offshore Wind Database shows at least nine floating projects are likely to come online by 2020, totaling 225MW – a further six projects in the pipeline provide upside potential. However, these technologies require significant investment and cooperation (WindFloat involved 60 suppliers), and each project is unique – standardization is key if floating offshore wind turbines are to be rolled out on a large scale. However, with some predictions that floating wind turbines could cut offshore wind costs in half, there are huge incentives for increased use of the technology.

Rachel Stonehouse, Douglas-Westwood London

www.douglas-westwood.com

▪ Integrated business model resilient through the commodity price cycle
▪ Company on track to grow daily production to 4.3 million oil-equivalent barrels by 2017
▪ Seven major Upstream project startups expected in 2015

Exxon Mobil Corporation (NYSE:XOM) expects to start up 16 major oil and natural gas projects during the next three years and is on track to increase daily production to 4.3 million oil-equivalent barrels by 2017, said Rex W. Tillerson, chairman and chief executive officer.

"Our long-term capital allocation approach has not changed," Tillerson said at the company's annual analyst meeting at the New York Stock Exchange. "We remain committed to our investment discipline and maintaining a reliable and growing dividend. Our integrated model along with our unmatched financial flexibility enable us to execute our business strategy and create shareholder value through the commodity price cycle."

In 2015, ExxonMobil expects to increase production volumes 2 percent to 4.1 million oil-equivalent barrels per day, driven by 7 percent liquids growth. The volume increase is supported by the ramp up of several projects completed in 2014 and the expected startup of seven new major developments in 2015, including Hadrian South in the Gulf of Mexico, expansion of the Kearl project in Canada, Banyu Urip in Indonesia and deepwater expansion projects at Erha in Nigeria and Kizomba in Angola.

In 2016 and 2017, production ramp up is expected from several projects including Gorgon Jansz in Australia, Hebron in Eastern Canada and expansions of Upper Zakum in United Arab Emirates and Odoptu in Far East Russia.

"ExxonMobil has a deep and diverse portfolio of opportunities around the world and a total resource base of more than 92 billion oil-equivalent barrels," Tillerson said. "We have unparalleled flexibility to select and invest in only the most attractive development projects."

ExxonMobil anticipates capital spending of about $34 billion in 2015 – 12 percent less than in 2014 – as it continues to bring major projects online. Annual capital and exploration expenditures are expected to average less than $34 billion in 2016 and 2017.

"We are capturing savings in raw materials, service, and construction costs," Tillerson said. "The lower capital outlook also reflects actions we are taking to improve our set of opportunities while enhancing specific terms and conditions and optimizing development plans."

ExxonMobil's Downstream and Chemical businesses remain resilient in the lower commodity price environment and continue to generate solid cash flow, helped by abundant North American crude and natural gas supplies that have led to lower feedstock and energy costs, Tillerson said.

Approximately 75 percent of ExxonMobil's refining operations are integrated with chemical and lubricant manufacturing, resulting in economies of scale and greater flexibility to produce higher-value products, including diesel, jet fuel, lubes, and chemicals based on market conditions, Tillerson said.

During the meeting, ExxonMobil reviewed its leading performance in 2014. Highlights include:
▪ ExxonMobil distributed $23.6 billion to shareholders in the form of dividends and share repurchases, for a total cash distribution yield of 5.4 percent.

▪ Return on average capital employed was 16.2 percent – more than 5 percentage points higher than its nearest competitor. During the past five years, return on capital employed averaged 21 percent, also about 5 percentage points above its nearest competitor.

▪ Upstream profitability of $19.47 per barrel led competitors and increased by $1.44 per barrel compared with 2013.

▪ ExxonMobil replaced 104 percent of production by adding proved oil and gas reserves totaling 1.5 billion oil-equivalent barrels, marking the 21st-consecutive year the reserves replacement exceeded 100 percent.

The Island Offshore Group reports 2014 revenue of NOK 2.732 mill which is 25% higher than 2013. Fleet utilization was 91% in 2014 which is satisfactory considering completion of a significant maintenance and modification program and a disappointing spot market. A total of 5 new vessels was added to the fleet in 2014 and 2 vessels were sold during the year.

EBITDA for the year totals NOK 1.270 mill, up from NOK 885 mill in 2013. 2014 figures include a sales gain of NOK 277 mill.

2014 profit before tax is NOK 406 mill including unrealized disagio of NOK 210 mill related to conversion of USD denominated loans.

In addition to strong financial results, significant improvement in important QHSE figures was achieved during 2014, hereto reduced personnel injury frequency rate and reduction of the fleet's emission of CO2.

Our strategy remains firm with focus on securing long term commitment with strategically preferred clients. The Group's order backlog is still strong and totals NOK 6.4 billion which equals approximately 2.4 times 2014 revenue.

Contract coverage for 2015 is approximately 80%.

NYC-based PIRA Energy Group believes resource control policies remained in a holding pattern in 2014, despite the collapse in oil prices in the second half of the year. In the U.S., commercial stocks decline slightly. In Japan, crude runs stay high, crude stocks build, and products drew. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Lower Oil Prices Do Not Yet Affect Resource Control Policies
Resource control policies remained in a holding pattern in 2014, despite the collapse in oil prices in the second half of the year. Some marginal easing of contract terms did materialize in countries including Argentina, China, and the UK, but the majority of oil-producing countries maintained their existing policies toward foreign and private investment. Moreover, history suggests it would take a few more years of depressed prices to trigger a widespread move to ease contract terms and accommodate foreign investment.

Overall U.S. Commercial Stocks Slightly Decline
Last week's large crude stock increase was met for the first time this year with an even larger product stock decline, causing overall inventories to fall, for the first stock decline in 2015, albeit modest. Stocks fell a little bit more last year for the same week, pushing the year on year inventory surplus up. Crude oil accounts for 63 million barrels, or 45%, of the year on year surplus.

Japanese Crude Runs Stay High, Crude Stocks Build, Products Draw
Crude runs rose again and reached their highest level since mid-March of last year. Crude imports remained strong and crude stocks built. Finished product stocks drew with moderate draws for naphtha and kerosene, and lesser draws on the other major products. The indicative refining margin remained strong, with all the major product cracks firming.

Mont Belvieu NGLs Outperform
Strong heating demand drove a major draw in domestic propane stocks and was enough to keep propane prices unchanged on the week, despite a 5.5% decrease in crude prices. Butane prices gave up 1.6% as the end of blending season nears, while natural gasoline fell 1% week-on-week. Ethane was carried higher with natural gas, increasing 1.2¢ to 18.9¢/gal.

Ethanol Prices Rise
U.S. ethanol prices advanced the week ending February 13. Economics held relatively steady for the second straight week, with margins for PIRA's model plant based on Chicago values improving slightly, while those for PIRA's Iowa plant worsening a little.

The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA's current analysis of energy markets around the world as well as the key economic and political factors driving those markets.

NYC-based PIRA Energy Group believes that Oil balances remain in surplus with pressure peaking in April/May. In the U.S., last week's data was impacted by fog and now this week marine traffic has been halted. In Japan, crude runs continue to ease but crude stocks were lower. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Asia-Pacific Oil Market Forecast
Oil balances remain in surplus with pressure peaking in April/May from rising crude stocks. Product stocks are more balanced but a growing overhang will unfold. The adjustment process to clear the Atlantic Basin crude surplus has been slow to unfold. Increased movements of North Sea crude to Korea occurred for March and April supporting Brent, but Middle East producers remain keen to maintain Asian market share.

Houston Ship Channel Problems Distorting Weekly Data
Last week's data was impacted by fog and now this week marine traffic has been halted in the Houston Ship Channel because of a collision between a chemical tanker and a bulk carrier and resulting MTBE spill. Almost 1.45 MMB/D of refining capacity is located in this vital shipping area. Crude imports and product exports not surprisingly have been delayed, and also runs have been curtailed. With much lower product exports, which were already expected to be low with a closed distillate export arb, reported demand is very low, hitting a new low for the year this past week of 18.61 MMB/D, down 1.0 MMB/D week-on-week.

Japanese Crude Runs Continue to Ease but Lower Crude Stocks and Higher Product Stocks
Crude runs eased again as maintenance gathered steam. Crude stocks drew on a low import figure, while finished product stocks built. All the major products built stocks slightly. The indicative refining margin remained strong. Gasoline and gasoil cracks firmed, thus offsetting declines in the fuel oil, naphtha, and jet fuel cracks.

Latin American Oil Market Report
Latin American light product imports will level off in 2015. New and returning refinery capacity in Brazil, Colombia, and Ecuador will boost refinery runs covering demand growth. Net gasoline and diesel imports in those three countries will decline in 2015.

U.S. Distillate Demand Weakness Due to Declining Long-Haul Truck Traffic
U.S. distillate demand has been weaker than generally expected. PIRA's internal models estimate the loss at roughly 120 MB/D in 2013 and by 125 MB/D in 2014. This note identifies long-haul trucking as the likely explanation for this weakness. Based on a statistical investigation of the decline in long-haul trucking, we estimate the annual average loss in distillate due to the fall-off in long-haul trucking at 118 MB/D for 2014 and 82 MB/D in 2013.

The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA's current analysis of energy markets around the world as well as the key economic and political factors driving those markets.

NYC-based PIRA Energy Group reports that February Cushing inventories rose and the WTI contango deepens. In the U.S., record crude stocks testing limits of storage capacity. In Japan, crude runs eased and stocks drew. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

February Cushing Inventories Rise; WTI Contango Deepens
Inventories continued to rise at Cushing, fueling deepening WTI contango, despite a rise in absolute prices after seven consecutive monthly declines. As Cushing fundamentals weakened, differentials to WTI strengthened across the board — from Alberta and Wyoming to Texas and Louisiana. Meanwhile, onshore drilling activity continued to plunge, signaling an approaching near-term hiatus in month-on-month shale production growth.

Record U.S. Crude Stocks Testing Limits of Storage Capacity
Gauging exactly how much crude storage capacity remains available has been a hot topic of late, and last week's build, propelling U.S. crude stocks to a new record, will certainly add to the urgency of this discussion. PIRA sees crude stock build continuing, testing the limits of onshore storage capacity.

Japanese Crude Runs Eased and Stocks Drew
Crude runs eased again from maximum seasonal levels, while imports were low enough to induce a stock draw. Finished product stocks also drew moderately. Gasoline demand was modestly higher, but lower incremental exports built stocks fractionally. Gasoil demand eased with higher yield, but a jump in incremental exports drew stocks yet again for the sixth straight week. The indicative refining margin remained strong. Gasoline, naphtha, and gasoil cracks firmed, thus offsetting a decline in the fuel oil crack.

Shift in PADD V Crude Balances Allowing ANS Exports
ANS exports are allowed but rare due both to infrequent arbitrage incentives and the requirement that U.S. flag vessels be used. With recent re-opening of arb incentives over the last two weeks, there is the potential for a near-term export. Longer term, with increased rail crude to PADD V and potentially more U.S. flag vessel availability (due to lower requirements as ANS production declines), occasional export opportunities are more likely.

Deferring Well Completions in a Low Crude Price Environment
As shale oil operators discuss in detail their plans for 2015, much attention has been paid to announcements of deferred well completions. The current contango market presents an opportunity for operators to improve well economics by deferring well completions to reap the benefits of higher future prices and perhaps also lower completion costs.

Onshore Crude Storage Will Be Close to Full in April
PIRA estimates the practical maximum storage capacity in the three major OECD markets. PIRA sees crude inventory levels building close to these levels by the end of April and even somewhat higher in May.

The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA's current analysis of energy markets around the world as well as the key economic and political factors driving those markets.

The low oil price is expected to dramatically impact O&G activity on the UKCS. Most notably, the number of wells drilled will decrease – particularly E&A wells. In 2014, drilling campaigns were significantly smaller than forecast – only 14 exploratory wells were drilled from an anticipated 25. This is the lowest number since 1970 and with the current oil price an increase is highly unlikely. However, production is expected to be maintained over the short to mid-term, bolstered by sanctioned projects. Meantime operators are seeking to control costs – BP and Talisman have recently announced large job cuts and many high Capex developments will face delays.

Despite the downturn, the 28th licensing round (November 2014) appears to indicate continued Operator interest. DECC awarded a total of 134 licenses – fewer than the record 27th round in 2012 – but still demonstrating the ongoing attractiveness of the region. This does not mean drilling will return to higher levels: the majority of licenses were awarded on the basis of further analysis of seismic data. Overall, oil companies committed to just five firm wells and four contingent wells. Given the declining oil price and current unattractive fiscal regime, a lack of commitment from oil companies is to be expected. However, the lack of drilling activity still represents a significant concern for the UK industry and encouraging companies into drilling will require careful restructuring of both the fiscal and regulatory framework.

Chancellor George Osborne, in his Autumn Statement, announced plans to revise the fiscal regime and appoint a new regulator. However, given the steep decline in oil price, more needs to be done, particularly on taxation – indeed Lord John Browne recently suggested cutting through the tax complexity and putting it onto a corporation tax basis. However, much depends on the outcome of the general election – anything but a win for Conservatives may delay much needed reforms and suppress the UKCS O&G industry further.

Balwinder Rangi, Douglas-Westwood London
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www.douglas-westwood.com

According to the United States Geological Survey, the area above the Arctic Circle holds approximately 90 billion barrels of undiscovered, technically recoverable oil and an estimated 1,670 trillion cubic feet of technically recoverable natural gas. Nevertheless, due to it being relatively inaccessible, Arctic oil commands the highest breakeven prices, typically ranging between $70 and $120 per barrel. In light of the current low oil price environment, Arctic projects are at risk of being deferred or cancelled.

Statoil has already halted plans to drill in the Barents Sea this year and has also let several Arctic exploration licenses off Greenland expire. In addition, the company's Johan Castberg project could face delay for the third time. As announced in December 2014, Chevron has cancelled plans to drill in Canada's Arctic, and in Russia, Western sanctions have thwarted Rosneft's plans to explore Arctic waters. The Russian state-controlled oil company will not be able to continue drilling in the Kara Sea in 2015 as a result of sanctions prohibiting its cooperation with ExxonMobil; drilling may begin in 2016 at the earliest.

Though there is widespread negativity surrounding projects, there is hope for Arctic oil yet. After a two-year hiatus, Shell plans a return to Arctic oil drilling this summer, in Alaska's Chukchi Sea. The super major will however, need to win permits and overcome legal objections to do so. Shell has already spent $1 billion on preparations for the drilling work. Another company that aims to continue drilling in the Arctic is Lundin Petroleum. The Swedish independent operator will carry on exploring the Barents Sea for new fields despite current market trends and in favour of a long-term view which they believe will deliver value in the future. This year, Lundin plans to drill four exploration wells and OMV, Wintershall and Eni one each.

Hannah Lewendon, Douglas-Westwood London

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The global offshore accommodation market has seen significant growth over the past five years, with PoB requirements increasing by 27% between 2009 and 2014. Although the recent oil price decline has negatively impacted the accommodation market to some extent, the affect thus far has been largely limited to demand for units supporting Capex-related activities.

However, Capex support is proportionally smaller in terms of total accommodation demand; of greater significance are the Opex markets which will account for 69% of PoB requirements in 2015. Accommodation units are utilised to reduce downtime during periods of essential maintenance. In the current oil price environment, sustaining production levels is key; moreover, reducing downtime from vital maintenance programs will be essential. DW analysis suggests growth within the accommodation market for units supporting Opex activities will be sustained, with at 3% CAGR forecast to 2020.

With Operators asking how they can increase worker efficiency, improving the level of crew welfare is a priority, particularly for IOCs. As the focus on welfare grows in prominence, newbuild accommodation units are being built with high levels of crew comfort in mind. Of particular focus is the maximum number of workers per cabin. The UK HSE is a driving force in this regards; the "Double Occupancy" standard limits cabins in accommodation units serving the UKCS assets to a maximum occupancy of two workers per room. Units sleeping four or more workers within the same room are becoming less desirable outside of price sensitive regions such as West Africa or the Middle East. Interestingly, the provision of WI-FI and quality food are key criteria cited by Operators in an attempt to please their workforce.

With the current oil price environment, the question is whether welfare will be sacrificed in favor of accommodation units with lower day rates. Potentially there is a trade off with regards to increasing worker efficiency through the provision of a comfortable offshore living space versus the need to reduce costs. The choice is likely to depend on the type of Operator, their preferences and regional regulations.

Kathryn Symes, Douglas-Westwood London
www.douglas-westwood.com

The low oil price is having major impact across the oil & gas industry. However, DW's recently released World Floating Production Market Forecast 2015-2019 expects capital expenditure on FPS units to total $81bn between 2015 and 2019. While many industry participants may consider this surprising due to daily announcements of budget cuts, it is important to note that while a number of FPS projects have been put on hold, few have cancelled – indicating that operators are simply employing wait-and-see tactics on projects. Over the next five-years, deepwater projects in the 'golden triangle' of Latin America, US Gulf of Mexico and West Africa, are expected to account for more than 60% of FPS expenditure. This is not unexpected given diminishing reserves in many onshore areas and in shallow waters, coupled with the widely accepted fact that floating production systems are a key enabler for production in deep waters.

Deepwater West Africa, particularly offshore Angola and Nigeria, is a growing market despite the current downturn. As we noted in February, while cuts in expenditure are being announced, IOCs are pressing ahead with key projects in both countries, all of which are expected onstream before 2018. Chevron, ExxonMobil and Eni all have major deepwater projects in Angola, collectively adding a peak capacity of approximately 1 million barrels per day. Total also has a number of FPS projects in development – examples include the Eastern Hub FPSO in Angola and the Egina FPSO in Nigeria.

While Petrobras is currently embroiled in a corruption scandal, a number of the NOC's FPS units were ordered prior to the oil price downturn therefore these projects are unlikely to be affected. However, future orders have some uncertainly due to the scandal. Overall, due to the growing importance of deepwater reserves, associated floating production activity is expected to increase despite the oil price downturn. As such, offshore West Africa will remain a key area for FPS deployments and oil & gas stakeholders' interest in the region is well placed.

Damilola Odufuwa, Douglas-Westwood London
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www.douglas-westwood.com

NYC-based PIRA Energy Group believes current Brent crude tightness will not last. In the U.S., crude build drives another record total U.S. commercial stock level. In Japan, crude runs eased and product stocks drew. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

World Oil Market Forecast, February 2015
PIRA's outlook for an improving global economy is on track. Current Brent crude tightness will not last. The basic problem is that the Atlantic Basin has no outlet for its excess crude, with Middle East producers aggressively pricing in Asia to maintain market share. The surplus hit Europe first, then North America, and now all prices point supply back to Europe.

Crude Build Drives another Record Total U.S. Commercial Stock Level
The U.S. crude balance structure that has bloated crude inventories to record levels continues unabated. Domestic crude supply is now up more than 1.5 MMB/D over the last four weeks, compared to last year, while crude imports remain stubbornly high, down only 0.55 MB/D over the same period. Weekly crude runs and exports are up a combined 0.7 MMB/D, but not nearly enough to forestall stocks growing at a faster clip than last year. Total commercial stocks built this week, to a new record high. With a draw last year, the year-over-year surplus increased. With falling crude runs but imports remaining around 7.30 MMB/D, crude stocks built.

Japanese Crude Runs Easing; Crude and Product Stocks Draw
Crude runs have begun to ease from maximum seasonal levels, while imports were low and crude stocks drew. Finished product stocks also drew moderately. Gasoline demand eased, but stocks still drew slightly, while gasoil demand was strong and stocks drew for the fifth straight week. The indicative refining margin remained strong. Gasoline cracks firmed, while other major product cracks eased slightly.

European LPG Prices March Higher
European LPG prices rose last week as higher winter demand was met by limited supply, as fewer import cargoes arrived in the region and refinery supplies have dwindled. Barge lots of propane were $39/MT higher at $533 Friday, at a slight premium to naphtha. Weather related export disruptions in Algeria and more expensive naphtha prices have also been bullish catalysts.

Ethanol Production Declines
U.S. ethanol production declined sharply during the week ending February 20 to a 15-week low 947 MB/D from 964 MB/D during the previous week. Inventories built by 510 thousand barrels to a 2½-year high 21.6 million barrels.

A Look at Political Risks in a Low Oil Price Environment
Supply disruptions continued to grow in 2014, but the growth in losses nearly halved relative to recent years, and the vast oversupply in today's global oil market is muting the impact of losses. While PIRA expects slightly lower disruptions in 2015, we believe important risks to supply are lurking. As in years past, violence and political turmoil do remain a threat, but this year risks are also emanating from the low oil price environment. In this note, we look at political risks in the $50-$60/Bbl oil price environment expected this year. PIRA believes the biggest risks to supply in 2015 come from presidential elections in Nigeria; economic deterioration in Venezuela; and fiscal constraints and political tensions between Baghdad and Kurdistan.

The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA's current analysis of energy markets around the world as well as the key economic and political factors driving those markets.

Despite the dramatic recent weakening in global energy markets, ongoing economic expansion in Asia – particularly in China and India – will drive continued growth in the world's demand for energy over the next 20 years. According to the new edition of the BP Energy Outlook 2035, global demand for energy is expected to rise by 37% from 2013 to 2035, or by an average of 1.4% a year.

The Outlook looks at long-term energy trends and develops projections for world energy markets over the next two decades. The new edition was launched today in London by Spencer Dale, BP's group chief economist, and Bob Dudley, group chief executive.

"After three years of high and deceptively steady oil prices, the fall of recent months is a stark reminder that the norm in energy markets is one of continuous change," said Spencer Dale. "It is important that we look through short term volatility to identify those longer term trends in supply and demand that are likely to shape the energy sector over the next 20 years and so help inform the strategic choices facing the industry and policy makers alike."

US tight oil grows
The Outlook projects that demand for oil will increase by around 0.8% each year to 2035. The rising demand comes entirely from the non-OECD countries; oil consumption within the OECD peaked in 2005 and by 2035 is expected to have fallen to levels not seen since 1986. By 2035 China is likely to have overtaken the US as the largest single consumer of oil globally.

The current weakness in the oil market, which stems in large part from strong growth in tight oil production in the US, is likely to take several years to work through. In 2014, tight oil production drove US oil output higher by 1.5 million barrels a day – the largest single-year rise in US history. But further out, the growth in tight oil is likely to slow and Middle East production will gain ground once more.

By the 2030s the US is likely to have become self-sufficient in oil, after having imported 60% of its total demand as recently as 2005.

Gas rising fast; coal slow
Demand for natural gas will grow fastest of the fossil fuels over the period to 2035, increasing by 1.9% a year, led by demand from Asia.

Half the increased demand will be met by rising conventional gas production, primarily in Russia and the Middle East, and about a half from shale gas. By 2035, North America, which currently accounts for almost all global shale gas supply, will still produce around three quarters of the total.

Coal had been the fastest growing of the fossil fuels over the past decade, driven by Chinese demand. However over the next 20 years the Outlook instead sees coal as the slowest growing fossil fuel, growing by 0.8% a year, marginally slower than oil. The change is driven by three factors: moderating and less energy-intensive growth in China; the impact of regulation and policy on the use of coal in both the US and China; and the plentiful supplies of gas helping to squeeze coal out from power generation.

LNG grows, becoming dominant in trade
As demand for gas grows, there will be increasing trade across regions and by the early 2020s Asia Pacific will overtake Europe as the largest net gas importing region. The continuing growth of shale gas will also mean that in the next few years North America will switch from being a net importer to net exporter of gas.

The overwhelming majority of the increase in traded gas will be met through increasing LNG supplies. Production of LNG will show dramatic growth over the rest of this decade, with supply growing almost 8% a year through the period to 2020. This also means that by 2035 LNG will have overtaken pipelines as the dominant form of traded gas.

Increasing LNG trade will also have other effects on markets. Over time it can be expected to lead to more connected and integrated gas markets and prices across the world. And it is also likely to provide significantly greater diversity in gas supplies to consuming regions such as Europe and China.

Energy flowing east
Energy self-sufficiency in North America - which is expected to become a net exporter of energy this year - and increasing LNG trade are also over time expected to have fundamental impacts on global energy flows.

Increased oil and gas supplies in the US and lower demand in the US and Europe due to improving energy efficiency and lower growth will combine with continuing strong economic growth in Asia to shift the energy flows increasingly from west to east.

Carbon emissions continue to grow
The Outlook also considers global CO2 emissions to 2035 based on its projections of energy markets and the most likely evolution of carbon-related policies. Its projection shows emissions rising by 1% a year to 2035, or by 25% over the period, on a trajectory significantly above the path recommended by scientists as illustrated, for example, by the IEA's "450 Scenario."

To abate carbon emissions further will require additional significant steps by policy makers beyond the steps already assumed, and the Outlook provides comparative information for possible options and their relative impacts on emissions. However, as no one option is likely to be sufficient on its own, multiple options will need to be pursued. This underlines the importance of policymaking taking steps that lead to a meaningful global price for carbon which would provide incentives for everyone to play their role in meeting the world's increasing energy needs in a sustainable manner.

Commenting on the Outlook, Bob Dudley concluded: "The energy industry works on strategies and investments with lifespans often measured in decades. This is why an authoritative view of the key trends and movements that will shape our markets over this long term is essential... and is precisely why this Outlook is so valuable."

Go to www.bp.com/energyoutlook to download the Outlook or additional country & regional insights, and view other material such as videos or an animation.