2015 may well be remembered as the year when natural gas truly announced itself as the major energy fuel source. With the announcement that Shell are targeting a $70bn deal for BG Group, and in doing so increasing their current LNG capacity to around 33 million tons per annum, the big dollars to secure gas capacity are coming into sharp focus. Should the acquisition complete, Shell will have access to gas resources from Trinidad & Tobago to Tanzania. BG’s Queensland Curtis LNG project could also provide a viable option to develop the major Arrow coal-seam gas development in Australia.

Elsewhere in Australia, Chevron is expecting to see first production from the defining Gorgon project by Q3 this year. A massive LNG project with estimated capacity of 15.6 million tons per annum, Gorgon is expected to boost the company balance sheet for 40 years. Described as a black hole for Capex following well known cost overruns – expected to approach 50% of the initial $37bn budget – safe and timely execution this year will be critical not only for the company but for the future of Australian supply capacity. Similarly, 2015 is a big year for the Wheatstone LNG sister project as major modules are completed and project integration continues prior to 2016 operation.

After much anticipation, the world’s first floating LNG vessel is also expected to begin operations for Petronas in Q4. The FLNG 1 represents a major technological advancement in the monetization of offshore gas assets. The success or otherwise of this unit, along with that of the under-construction Prelude (to begin operations for Shell in 2016), could signal the beginning of an era where stranded gas, marginal fields and major offshore gas discoveries can be processed offshore.

Acquisitions, major capital projects and large-scale technical developments suggest that 2015 is a fulcrum year for global gas supply.

Matt Loffman, Douglas-Westwood Houston

+1 713 714 4795 or This email address is being protected from spambots. You need JavaScript enabled to view it.

www.douglas-westwood.com

NYC-based PIRA Energy Group believes that the positive impact of lower oil prices on global economic growth is beginning to be seen but oil markets remain oversupplied. In the U.S., oil inventories built this past week. In Japan, turnarounds gear up, but crude and product stocks draw. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

World Oil Market Forecast, March 2015
The positive impact of lower oil prices on global economic growth is beginning to be seen but oil markets remain oversupplied with a 2 MMB/D surplus in the second quarter, which will continue to negatively impact physical markets. New price lows for Brent are unlikely and WTI is not expected to go below $40/Bbl. Both prices are anchored by the back of the market and available storage capacity, even if it is floating. The magic of price is working to tighten oil markets but it takes time. Gasoline season looks healthy but new refinery capacity will pressure distillate. Political uncertainties are on the rise with this weekend's Nigerian elections, Saudi Arabia's direct military involvement in Yemen, and turmoil in Libya, among other things.

U.S. Inventories Lead the March Surge
U.S. oil inventories built this past week, bringing the March stock build to nearly 1 MMB/D. Relative to last year U.S. inventories are 164 million barrels, or nearly 16% higher than last year. Over half of the excess is in crude oil.

Japanese Turnarounds Gear Up, but Crude and Product Stocks Draw
Crude runs eased again as maintenance continues to pick up pace. Crude stocks drew to a record low on a low import figure, while finished product stocks also drew on higher demands and lower runs. The indicative refining margin remained strong.

LPG Stocks Building from Record Base
U.S. propane inventories increased by 638 MB, the second consecutive weekly build - signaling that the bottom for stocks has likely been put in, and that stocks will continue to build thru September from this high base level of 50.3 MMB. Stocks of NGLs and LRGs (excluding propane) more than doubled their prior week's gain to 1.1 MMB, bringing inventories to 77.3 million barrels, 15.2 MMB above the year ago volume.

Ethanol Stocks Decreased for Third Consecutive Week
U.S. ethanol prices declined at the beginning of the week ending March 20, but strengthened after the DOE reported an inventory draw for the third consecutive week. The output of ethanol-blended gasoline rose to a twelve-week high.

Biofuels Programs Continue in Over 60 Countries
Canada imported 1.2 billion liters (318 million gallons) of ethanol in 2014 to help satisfy its 5% ethanol mandate. Essentially all imports come from the U.S. In Mexico, PEMEX awarded contracts for the supply of up to 123 million liters (32.5 million gallons) per year from locally sourced sugarcane and sorghum.

Yemen: Saudi Intervention Adds $3-$5 Risk Premium Only Temporarily Because Of Low Physical Supply Risks
Saudi Arabia's intervention in Yemen with Kuwait, Qatar, the UAE, Bahrain and Egypt contributes to growing instability and unpredictability in the region, but poses little direct threat to oil and gas supplies. While the physical supply risks are low at this point, Saudi's decision does add $3-$5/Bbl to the risk premium, which began to be priced in late yesterday. This premium will gradually erode over time if large supply disruptions do not materialize (which is what we expect).

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.

NYC-based PIRA Energy Group reports that Cushing stocks hit a record high in March. In the U.S., the crude stock surplus hits a new high. In Japan, crude runs ease with higher maintenance and crude and finished product stocks post slight builds. Specifically, PIRA’s analysis of the oil market fundamentals has revealed the following:

Cushing Stocks Hit Record High in March

Cushing crude stocks rose to record levels in March, causing the NYMEX WTI contango to widen and strengthening most onshore crude differentials, as Cushing WTI prices weakened relative to regional grades. Outright prices weakened through the first half of March, but began to recover by month end, helped by improved refining margins and geopolitical risks. Stocks at Cushing are expected to peak just above 60 million barrels in April or May. But WTI will remain in contango until stocks fall toward the 30-35 million barrel level — not likely until at least mid-2016.

U.S. Stock Surplus Hits New High

With the largest weekly inventory increase of the year, the year-on-year inventory surplus swelled to 177 million barrels, or 17%. Crude stocks are almost 100 million barrels higher than last year. Gasoline and distillate inventories are a combined 33 million barrels higher.

Japanese Crude Runs Ease with Higher Maintenance; Crude and Finished Product Stocks Post Slight Builds

Crude runs eased and remain in good alignment with our turnaround schedules. Crude imports also declined, but crude stocks still posted a modest build. Gasoline and gasoil stocks drew slightly despite falling demands. Kerosene stocks built as demand seasonally ebbed. The indicative refining margin remained strong, though major product cracks softened on the week.

Aramco Differentials Announced, Asia Raised

Saudi Arabia's formula prices for May were just released. U.S. and European differential adjustments were mixed and seen as minor. European differentials were tweaked, higher on the lightest and heaviest grades, and cut marginally on Arab Light. U.S. differentials were lowered on Arab Extra Light and Light and lowered on Arab Medium and Heavy. Differentials to Asia, however, were raised more significantly and across the board. The adjustments for all regions are seen as keeping in step with refiner demand for crude and downstream profitability.

Saudi Arabia Producing 10.3 MMB/D: Bullish or Bearish?

On balance, Saudi Arabia producing 10.3 MMB/D in March 2015 is bullish. Incremental Saudi crude burn demand could push its volume this summer to levels that would substantially reduce global spare capacity, at a time when oil markets will be tighter and geopolitical risks to supply are growing. Look for Saudi Arabia to continue to increase prices to restrain demand as it has done the last two months. All of this will be supportive to higher oil prices in second-half 2015.

Asian Steam Cracker Margins at 2015 Highs

Asian steam cracker margins have been in a broad upswing since January of this year. Margins improved yet again last week and continue to make new 2015 highs. Naphtha cracks added 2¢ to 53¢/lb, but they look increasingly challenged by LPG in the coming weeks as heating demand deteriorates and prices weaken. Butane margins jumped 14% to 51¢/lb while propane cracks added 5¢ to 49¢/lb.

U.S. Ethanol Prices and Margins Increase

The week ending April 3, U.S. prices advanced to the highest levels of the year. Rising petroleum prices and robust demand for ethanol-blended gasoline were the main drivers. Margins also reached a 2015 high last week, as corn prices fell after bearish USDA reports.

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.

Deepwater expenditure is expected to increase by 69%, compared to the preceding five-year period, totaling $210 billion (bn) from 2015 to 2019. This is the headline finding from Douglas-Westwood's (DW) World Deepwater Market Forecast 2015-2019. Report author, Mark Adeosun, commented, "As production from mature basins onshore and in shallow water declines, development of deepwater reserves has become increasingly vital, particularly to the world's oil majors. However, the recent oil price decline has intensified pressure on operator budgets. Consequently, numerous operators have deferred sanctioning of capital intensive developments.

"DW has identified a trough in global expenditure in 2015 and 2016 primarily driven by delays to delivery of FPS units in Latin America. We expect deepwater Capex to rise post-2016, driven by the continued development of deepwater fields off Latin America and West Africa, as well as new developments off East Africa. However, in the short-term, delays as a result of the oil price are causing significantly slower growth than was expected a year ago."

Assistant report editor, Balwinder Rangi, continued, "Africa, Latin America and North America will continue to dominate deepwater Capex, with $173bn set to be spent over the next five years with Africa forecast to experience the greatest growth. The development of East African natural gas basins has not been aided by the plunge in Asian gas prices; however, the development of these gas basins is inevitable. The expected recovery of oil prices will spark a revival in LNG-related activities in the region towards the end of the forecast period. Latin America will, however, remain the largest market and North America is expected to experience the least growth.

"In addition to the low oil price environment and building oversupply, the lack of rig demand will impact Capex growth over the forecast period. Current, industry consensus indicates that an oil price recovery is expected in the mid-to-long term. Whilst the economic feasibility of deepwater fields varies, typically long-term oil prices of $80 per barrel would ensure the viability of the majority of developments."

www.douglas-westwood.com

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

Despite major cost reduction measures, Q1 2015 earnings for supermajors are expected to be the weakest in recent memory. Operational and financial indicators for FY 2014, however, reveal that recent performance amongst the big 5 has been far from homogeneous.

In short, the Americans outperformed the Europeans. Exxon and Chevron posted high net margins of 8.3% and 9.1%, respectively. Shell’s was a more modest 3.5%, whilst BP (1.1%) and Total (2.0%) struggled badly. Chevron and Total were the most aggressive risk takers, as their CAPEX-to-Sales ratios for the year stood at 19% and 14%, respectively, while the other majors conservatively avoided spending more than 10% of sales.

Among other factors, refining interests are a key driver of this disparate performance. While Exxon, Chevron and Shell refined broadly as many barrels as they extracted in 2014 (113%, 105% and 94%, respectively), BP and Total were much more exposed to upstream (55%, 83%) and have not benefitted from the traditional buffer effect of downstream activities in a low price environment.

Looking at the long-term indicators, not much change can be seen in the 2014 Proved Reserves-to-Production ratio – XOM 17.4, CVX 11.8, RDS 11.6, BP 15.2, TTA 14.7 (expressed in years). In an oversupplied market, the challenge is not to bring volumes, but value. In this respect, the Europeans looked to offset poor performance by building strong net cash positions – between $20-30 billion at year-end 2014 – to maintain dividends and shareholder confidence. However, while Exxon, Chevron and Shell managed to keep their Gross Debt-to-Equity ratio at around 20%, BP and Total ended the year with a degraded financial structure, at 47% and 62%, respectively.

Considering the above, Shell seems to be the healthiest among the European majors, but crucially lacking in long-term organic growth opportunities. In this light, the £47bn takeover of BG Group makes sense: it will boost Shell’s production by 20% and reserves by 25%, and also provides exposure to high-potential Brazilian assets. With similarly modest leverage and potential for quick cash generation, Exxon and Chevron are well positioned for their own M&A moves now the starting gun has sounded.

Antoine Paillat, Douglas-Westwood London

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www.douglas-westwood.com

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."

Diversification in to renewables and interconnector market rewarded Ecosse Subsea Systems Ltd (ESS) more than trebled profits to £3.4 million and increased revenue by 88% to £15.6 million according to its latest published accounts.

The Aberdeenshire-based subsea engineering specialist attributed the phenomenal growth to a diversification from its traditional oil and gas market in to renewables and interconnectors.

ESS has developed technologies which are in high demand for seabed clearance work, trenching and cable laying projects. In the past two years the company has made huge inroads in to the emerging renewables sector which now accounts for 55% of projects and builds upon an earlier focus on oil and gas contracts.

The accounts to March 2014 show turnover increased from £8.3 million to £15.6 million, while operating profit (EBITDA)* rose from £1.02 million to £3.4 million in the same period.

The drivers for ESS’s most successful trading year to date was a £5.4 million contract on the Baltic 2 windfarm offshore Germany and a multi-million pound cable-lay contract on behalf of an European utilities provider in the Humber Estuary.

Last month ESS also announced it had signed a Letter of Intent with ABB to provide seabed clearing and trenching services on the 100-mile £1.2 billion Caithness-Moray electricity transmission link project, which could end up as the company’s largest ever contract award.

The company employs 70 offshore and at its headquarters in Banchory near Aberdeen, which rose to 110 during the execution of offshore projects, and in the last year it has invested more than £1 million in research and development.

ESS managing director, Mike Wilson, said: “The results are extremely encouraging and confirm that our technologies are equally suited to and easily transferable between the oil and gas sector, which is where we cut our teeth, and the green energy market. Added to that, we have just won our first contract in the interconnector sector and we hope success on the Caithness-Moray project will lead the way to further awards in this field.”

Mr. Wilson said other parts of the business, including its engineering consultancy and personnel recruitment arms, had enjoyed a successful year and added significantly to the bottom line, while continued investment in new technologies was now bearing fruit.

He added: “We benefited greatly from research and development in our technologies starting to come through, and recognition from clients that we have developed a suite of tools which deliver measurable time and cost savings.

“Diversification is paying off for us as can be seen in these latest financial results and we will continue to look for new opportunities in other markets, including oil and gas and interconnector projects in Arctic waters where we have already received some interest.”

Mr. Wilson noted that ESS had already suffered from the effects of a low oil price with the cancellation of a number of oil and gas projects and said that while 2015 turnover would increase on the previous year, that margins would be tighter.

He added: “With a healthy balance sheet and debt-free status, we are in a strong position to counter the challenges facing the oil and gas industry while capitalizing on new opportunities in other markets.”

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%.