new base 1004 special 26 february 2017 energy news

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,

or otherwise copied without the written permission of the authors. This includes internal distribution. All reasonable endeavours have been used to ensure the accuracy of the information contained in this

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NewBase 26 February 2017 - Issue No. 1004 Senior Editor Eng. Khaled Al Awadi

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE

Saudi energy firm inks deal for Australian solar farm Arabian business

Fotowatio Renewable Ventures (FRV), a developer of large-scale solar power plants and part of Saudi-based Abdul Latif Jameel Energy, has signed a power purchase agreement for the Lilyvale Solar Farm in Queensland, Australia.

The deal with Ergon Energy, the Queensland Government-owned electricity retailer, will see Ergon Energy purchase 100 percent of the electricity and all large scale renewable energy certificates (LRECs) generated by FRV's 100MW Lilyvale Solar Farm project.

The agreement will be effective once the solar facility begins operation, expected to be towards the end of 2018, and run until 2030.

The proposed Lilyvale solar farm is located 50 kilometres North East of Emerald in the Queensland Central Highlands region, known for its many coal mines and cattle farming industry.

The project’s location near to major existing network infrastructure makes it ideal for connecting the solar farm to the national electricity grid, FRV said in a statement.

The project received approval in September 2015, with construction set to begin mid-2017 and expected to take 12-16 months. FRV estimates up to 200 workers will be needed to complete Lilyvale Solar Farm’s construction. It is expected to power approximtely 45,000 homes.

The announcement is the third power purchase agreement that FRV has signed in Australia within the last 12 months, following deals with Origin Energy for the Moree Solar Farm in New South Wales and the Clare Solar Farm, near Ayr in No-rth Queensland. FRV’s Chief Executive Officer, Rafael Benjumea, said: “FRV continues to demonstrate strong performance in securing long-term power purchase agreements to underpin its landmark solar power projects in Australia."




UAE: Emirates Transport to supply e-vehicles to finance ministry

The UAE Ministry of Finance (MoF) has signed an agreement with Emirates Transport for supply of electric-powered vehicles. The move comes as part of MoF’s commitment to support sustainable energy resources in line with UAE vision 2021, by using sustainable transport services offered by Emirates Transport- which contribute to clean energy and provide a healthy and safe environment, said Younis Haji Al

Khoori, the undersecretary of MoF after signing the deal with Mohammed Abdullah Al Jarman, the general manager of Emirates Transport. Al Khoori pointed out that this was part of the UAE leadership’s commitment to diversify energy resources and encourage adopting renewable resources to reduce harmful emissions. "We are working to enhance the environmental indicator results by embracing eco-friendly, electric-powered vehicles. This stems from our belief in the importance of sustainable

development and our commitment to future generations to provide a clean, healthy and safe environment," he added. Al Jarman said the signing of the MoU stems from the ministry’s commitment to achieving sustainable development. "It also helps in strengthening cooperation and partnership between Emirates Transport and the ministry," he noted. He also highlighted MoF’s efforts to achieve the Emirati vision and objectives to diversify energy resources and encourage dependency on renewable energy to reduce carbon emissions. Stressing the importance of adopting clean and sustainable energy for a healthy and safe

environment, Al Jarman said: "We considered this step as a reflection of the wise government’s ambitions to achieve integration between institutions through joint efforts between public and private companies." "The integration will be key for supporting initiatives and projects which achieve sustainable development, protect the future generation and achieve the UAE Vision 2021," he added.-




UAE: ADNOC to boost electric vehicle charging stations The national - LeAnne Graves

Abu Dhabi National Oil Company (Adnoc) Distribution plans to increase the number of electric vehicle (EV) charging stations across the emirate to 20 to meet the anticipated rise in petrol-alternative cars. EVs are expected to make headway in the country after the arrival of American car maker Tesla earlier this month. Abu Dhabi currently has 12 EV charging stations.

Saeed Al Rashdi, the acting chief executive of Adnoc Distribution, told The National that it had already started outfitting its Yas service station with a solar-powered electric charger, which will use power from the grid as backup for times when the sun isn’t shining.

“We are planning to extend the installation of similar chargers to seven other service stations – the Al Mushrif, Rabdan, Khalifa City-South, Abu Dhabi Corniche, Souk Al Batten, Samha-1 and Samha-2,” he said.

Adnoc has also concluded a joint survey with Tesla on the viability of installing chargers at service stations but no details have been released. Mr Al Rashdi said: “In view of the potential growth of electric car and hybrid usage, we are moving ahead with the early development of support infrastructure for such vehicles.”

While EVs were already in the UAE thanks to companies such as Renault, the debut of Tesla has resulted in an infrastructure race to meet potential demand. The American car maker opened a pop-up shop in Dubai Mall, with a Tesla Ranger support and service centre to open in July. The chief executive, Elon Musk, said that a shop and service centre would also open in Abu Dhabi next year.

The UAE has at least 85 charging stations, according to research by The National. In addition to Abu Dhabi’s 12, Dubai has 68 and there are five charging stations in Sharjah, Ras Al Khaimah and Fujairah.

There are three different types of chargers: AC Level 1 (slow, such as a wall socket), AC Level 2 (medium, between two and four hours) and DC fast charging (fast, less than 30 minutes).

For the slow charging wall socket at a home, UAE users will pay rates based on residential tariffs set out by the respective utility, the same way powering lights or devices is calculated in monthly electricity bills.

For a Tesla Model S owner in the capital averaging 20,000 kilometres a year, the annual cost for charging the battery at home is 10 to 30 per cent less than fuelling a conventional car, ranging from about Dh281 for a national to Dh1,144 for an expat.

For public charging stations in Abu Dhabi, private entities that own them will determine prices, according to the Abu Dhabi Distribution Company (ADDC). Potential station owners will need to contact ADDC so the distributor can confirm viability and inspect facilities.

In Dubai, Dubai Electricity and Water Authority (Dewa) will be in charge of every station, with public charging areas priced at 29 fils per kilowatt hour. If a Tesla Model S owner only uses Dewa-provided public charging stations, it will cost about Dh1,088 a year for 20,000km. This is half of what it would cost to fuel a 2017 BMW 5 Series sedan, which will run about Dh2,000 to Dh3,600 with petrol prices averaging Dh2 per litre.




China’s use of methanol in liquid fuels has grown rapidly since 2000 Source: U.S. Energy Information Administration, based on Argus Media Group

China is the global leader in methanol use and has recently expanded methanol production capacity. Since the early 2000s, China’s methanol consumption in fuel products has risen sharply and is estimated to have been more than 500,000 barrels per day (b/d) in 2016.

EIA commissioned a study from Argus Media group to better understand China’s consumption of methanol and its derivatives. The estimates developed in the study have now been incorporated into EIA’s historical data and forecasts of petroleum and other liquids consumption in China.

Methanol, like ethanol, is an alcohol with inherent issues such as its solubility in water and corrosiveness. Methanol or its derivative products can be added to fuels such as gasoline and liquefied petroleum gases (LPG). Similar to how ethanol is currently blended into motor gasoline in the United States, methanol is blended into gasoline in China.

Most of China’s methanol supply is from domestic production. About two-thirds of China’s methanol feedstock is produced from coal and the remainder from coking gas (a by-product of steel production) and natural gas. China has abundant coal resources, and for more than a decade the country has increased its capacity to manufacture methanol using coal as a feedstock. Smaller amounts of China’s methanol supply are imported from the Middle East, Southeast Asia, South America, and the United States.

Methanol is a clean-burning, high-octane fuel component, as the oxygen present in methanol aids in more complete fuel combustion. Blending methanol with gasoline allows refiners to extend China’s gasoline supply and increase the octane level of its gasoline. However, methanol has only one-half the energy per unit of volume as gasoline and requires more fuel consumption on a volumetric basis to provide the same amount of energy.




China’s largest city, Shanghai, and 13 of China’s 23 provinces have approved local standards for methanol blends ranging from 5% to 100% methanol. China has a national quality standard for methanol blends of 85%, and a national standard for a 15% blend of methanol in gasoline is pending approval by the government.

A methanol derivative known as methyl tertiary butyl ether (MTBE) is also blended into gasoline in China to increase octane levels. Consumption of MTBE and other derivatives in China was estimated at 230,000 b/d in 2016. Starting in the 1990s, MTBE was used as an oxygenate and octane enhancer in reformulated gasoline sold in the United States, with domestic production exceeding 200,000 b/d from 1998 to 2002. However, concerns over groundwater contamination led an increasing number of states to ban it. Following enactment of provisions of the Energy Policy Act of 2005 that were interpreted as reducing or eliminating legal defenses available to MTBE blenders, its use was soon phased out in the United States.

Methanol can also be converted directly to gasoline, and in China this conversion occurs much less often than the blending of methanol or its derivatives into gasoline. China built its first methanol-to-gasoline (MTG) plant in 2010, and since then, another 10 MTG plants have come online. MTG units involve high capital costs and are only cost-competitive when oil prices are high. Lower oil prices since late 2014 have reduced China’s MTG plant operating rates and have created uncertainty for investment in new MTG plants.

For blending into liquefied petroleum gases such as propane, China uses methanol to create a derivative known as dimethyl ether (DME), a compound that has the same molecular formula as ethanol but a different chemical structure. Despite an official ban on the use of DME in LPG cylinders, some DME has been blended into LPG delivered to China's residential sector. Over the past two years, though, two factors—stronger enforcement of the DME ban and lower price competitiveness of DME relative to LPG—have reduced the level of DME blending.




US: Liquefied natural gas exports expected to drive growth in U.S. natural gas trade… EIA, Annual Energy Outlook 2017 Interactive Table Viewer

The United States is expected to become a net exporter of natural gas on an average annual basis by 2018, according to the recently released Annual Energy Outlook 2017 (AEO2017) Reference case.

The transition to net exporter is driven by declining pipeline imports, growing pipeline exports, and increasing exports of liquefied natural gas (LNG). In most AEO2017 cases, the United States is also projected to become a net exporter of total energy in the 2020s in large part because of increasing natural gas exports.

In 2016, the United States was a net importer of natural gas, with net imports of 0.9 trillion cubic feet (Tcf), or 2.6 billion cubic feet per day (Bcf/d). As several LNG export projects currently under construction are completed, LNG exports are expected to make up a growing share of natural gas exports and to surpass pipeline exports of natural gas by 2020.

The Sabine Pass facility in Louisiana became the first operating LNG export facility in the Lower 48 states in 2016. By 2021, four LNG export facilities currently under construction are expected to be completed. Combined, these five plants are expected to have an operational export capacity of 9.2 billion cubic feet per day. After 2021, projected U.S. exports of LNG grow at a more modest rate as U.S. natural gas faces growing competition from other global LNG suppliers.

U.S. exports of natural gas by pipeline to Mexico are also expected to increase. U.S. exports to Mexico have doubled since 2009 and are projected to continue rising through at least 2020 as pipeline projects currently under construction are completed.




U.S. imports of natural gas, most of which come by pipeline from western Canada, are projected to continue declining. In addition to importing less natural gas from Canada, primarily from Alberta, increasing amounts of natural gas from the Marcellus and Utica basins in the Northeast and Midwest regions of the United States are expected to flow to eastern Canadian provinces.

Despite these trends, the United States is expected to remain a net importer of natural gas by pipeline from Canada through 2040 in all but one case in the AEO2017 analysis. In the High Oil and Gas Resource and Technology case, higher natural gas production leads to greater exports of natural gas, and the United States becomes a net exporter of natural gas by pipeline to Canada by 2030.

Source: U.S. Energy Information Administration, Annual Energy Outlook 2017 Interactive Table Viewer

The growth of natural gas exports, especially from new LNG terminals, sustains continued growth in U.S. natural gas production. In the Reference case, natural gas production is projected to grow through 2020 at about the same rate (3.6% annual average) as it has since 2005, when production of natural gas from shale formations began to grow rapidly.

After 2020, natural gas production grows at a lower rate (1.0% annual average) in the Reference case as net export growth moderates, energy efficiencies increase, and natural gas prices slowly rise.

Natural gas production and trade vary with different assumptions for resources and technology, macroeconomic growth, and world oil prices. In the High Oil and Gas Resource and Technology case, larger natural gas resource estimates and improved drilling technology lead to higher




domestic natural gas production, lower U.S. natural gas prices, and therefore, greater natural gas exports. Most of the increase in natural gas trade is from LNG exports, which grow to 8.4 Tcf (23 Bcf/d) in 2040.

However, LNG exports are highest in a case with high world oil prices. In the High Oil Price case, when consumers move away from petroleum products when other energy sources become economically favorable, global LNG demand increases and U.S. LNG exports reach 9.2 Tcf, or 25 Bcf/d. Compared with other LNG suppliers, U.S. LNG has the advantage of domestic spot prices that are less sensitive to global oil prices.

Conversely, in a scenario with more pessimistic assumptions for oil and gas resources and technology or a scenario with low world oil prices, LNG exports still increase, but remain below Reference case levels through 2040.




US:Dream of Offshore U.S Wind Power May Be Too Ugly for Trump by Joe Ryan and Jennifer A Dlouhy

Offshore wind companies have spent years struggling to convince skeptics that the future of U.S. energy should include giant windmills at sea. Their job just got a lot harder with the election of Donald J. Trump. The Republican president -- who champions fossil fuels and called climate change a hoax -- has mocked wind farms as ugly, overpriced and deadly to birds. His most virulent criticism targeted an 11-turbine offshore project planned near his Scottish golf resort that he derided as “monstrous.” Companies trying to build in the U.S., including Dong Energy A/S and Statoil ASA, are hoping to change Trump’s mind. They plan to argue that installing Washington Monument-sized turbines along the Atlantic coast will help the president make good on campaign promises by creating thousands of jobs, boosting domestic manufacturing and restoring U.S. energy independence.

“We are a billion-dollar heavy industry that is set to build, employ and invest,” Nancy Sopko, director of offshore wind and federal legislative affairs for the industry-funded American Wind Energy Association, said in an interview. “We have a great story to tell to this administration.” Significant Stakes

The push to win over the Trump administration comes as offshore wind is on the brink of success in North America after a decade of false starts. Costs are falling dramatically. Deepwater Wind LLC completed the first project in U.S. waters in August. And in September, the Obama administration outlined plans to ease regulatory constraints and take other steps to encourage private development of enough turbines to crank out 86,000 megawatts by 2050. That’s about the equivalent of 86 nuclear reactors.




“We are an industry on the rise,” Thomas Brostrom, Dong’s general manager of North America, said in an interview. “We want very much to come in and explain to the new administration what we can do for job creation and energy independence.” A White House spokeswoman did not respond to requests for comment. The stakes are big. Dong, Statoil, Deepwater and other companies secured a total of 11 leases to build offshore wind farms. To move forward, developers will need permits from multiple agencies and, in some instances, federal grants to refurbish ports. For instance, Deepwater’s 30-megawatt wind farm off Rhode Island benefited from a $22.3 million U.S. Transportation Department grant to upgrade piers and terminals for use as a staging area.

Talking Points

To be clear, installing turbines at sea requires years of planning, and Trump may be out of office by the time some developers need federal approvals. State governments, meanwhile, remain the biggest drivers of renewable energy development, because they can mandate that utilities get a certain amount of power from offshore wind or other sources. Nevertheless, offshore developers need a basic level of cooperation in Washington to keep the nascent industry moving forward. "They don’t want to lose the progress that they’ve made,” said Frank Maisano, a Washington-based energy specialist for the lobbying firm Bracewell LLP. Shoring up Trump administration support will require developers to shed climate change talking points and dispel any notions that offshore wind is an environmental relic of the Obama administration, said Timothy Fox, an analyst at Washington-based ClearView Energy Partners LLC. It may help that two of the biggest developers -- Dong and Statoil -- have deep roots in offshore oil and natural gas. Jobs will be at the crux their message. Erecting 600-foot (183-meter) turbines along the Eastern seaboard may boost employment in struggling port towns from South Carolina to Maine, generating an estimated 31,000 jobs in the Mid-Atlantic alone, according to the National




Renewable Energy Laboratory. And if the industry booms, turbine manufacturers including Vestas Wind Systems A/S and Siemens AG have said they may open U.S. factories. Key Figures

"Logically there should be a good match here with the Trump administration," Kit Kennedy, the Natural Resources Defense Council’s director of energy and transportation, said in an interview. "We will see if ideology gets in the way." Persuading the president himself could be challenging. The bare-bones energy plan posted on the White House website calls for increasing coal, oil and gas production -- but makes no mention of wind or other forms of clean energy. Trump in 2012 tweeted: “Not only are wind farms disgusting looking, but even worse they are bad for people’s health.” Ultimately it’s unclear whether Trump’s 140-character appraisals of wind energy will translate into U.S. policy, or if they were simply reactions to windmills potentially spoiling views from his golf course in Aberdeenshire, Scotland. Either way, the commander-in-chief’s personal support may not be crucial for developers in the U.S. The key figures for offshore wind companies to persuade are deputy secretaries, directors and others within the Interior and Energy departments. A central player is the yet-to-be-named director of the Bureau of Ocean Energy Management, an Interior Department agency responsible for granting leases to offshore oil, gas and wind developers. Potential Allies

The industry may already have a few key allies. Rick Perry, Trump’s proposed energy secretary, oversaw a record expansion of wind energy during his time as Texas governor. And at least one high-ranking official who has supported offshore wind at the Bureau of Ocean Energy Management -- Acting Director Walter Cruickshank -- remains in place. The most important business stories of the day. Trump’s rise to power does not appear to have curbed offshore wind developers’ enthusiasm about the U.S. market. Weeks after the election, Norway’s Statoil paid a record $42.5 million for a lease to develop a site off the coast of New York. And at least nine companies -- including a unit of oil giant Royal Dutch Shell Plc. -- have qualified to bid next month for a lease to build off North Carolina. “There is a misconception that wind energy is all driven by climate change,” said Danish ambassador Lars Gert Lose, who is helping Fredericia, Denmark,-based Dong with lobbying efforts. “But this is a very competitive industry.”




NewBase 26 February 2017 Khaled Al Awadi

NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE

Oil prices settles at $53.99 & $56.00, ending the week higher as OPEC cuts offset rising US supply Reuters + NewBase

Oil prices fell on Friday on concerns over rising U.S. supplies and as traders begin to pull out crude barrels from pricey storage.

Book squaring ahead of the weekend and ahead of upcoming Feb. 28 expirations in Brent futures for April delivery, heating oil for March delivery, and March RBOB gasoline, also pressured prices, analysts and traders said.

U.S. West Texas Intermediate settled down 46 cents at $53.99 a barrel, ending the week's trade 1.1 percent higher.

Benchmark Brent crude oil was down 58 cents at $56 a barrel by 2:35 p.m. ET (1935 GMT). The contract was on pace for a slight weekly gain.

The latest sign of renewed U.S. production came on Friday after oilfield service firm Baker Hughes reported its weekly count of U.S. oil rigs topped 600 for the first time since October, 2015. Last week, drillers added 5 oil rigs.

U.S. crude stocks rose by 564,000 barrels in the week to Feb. 17, the Energy Information Administration reported Thursday, although the gain was below analysts' expectations for an increase of 3.5 million barrels.

Oil price special

coverage




But prices have been supported and trading in a tight $4-5 range since November when the Organization of the Petroleum Exporting Countries (OPEC) and other producers agreed to cut production.

"The oil market remains focused on the global rebalancing act, with attention centered on OPEC compliance and U.S. production growth," said Michael Tran, director of energy strategy at RBC Capital Markets in New York.

"The push-pull situation between stock draws relative to price-elastic U.S. shale remains paramount to the rebalance."

OPEC has so far surprised the market by showing record compliance with the deal and could do so further in coming months as the biggest laggards - the United Arab Emirates and Iraq - pledge to catch up quickly with their targets.

OPEC's average compliance is put by the International Energy Agency at a record 90 percent in January, and based on a Reuters average of production surveys, it stands at 88 percent.

However, exports from the United States, which is not part of the deal, hit a record high of 1.2 million barrels per day (bpd) last week and production rose to above 9 million bpd, the highest since April, the U.S. Energy Administration Agency said. Meanwhile, traders are turning the spigots to drain the priciest U.S. storage tanks and selling oil held in tankers anchored off Malaysia, Singapore and Indonesia as the rising price of oil for near-term delivery erodes the profits to be had by holding onto oil for later sale. Analysts at LBBW said that the continued growth in U.S. production and oil prices that look to have reached a technical ceiling have led them to cut their year-end Brent price forecast by $5 to $55 a barrel. "Most market participants realize that the good news from OPEC seems to be priced in; therefore, and because of the shale comeback (in the U.S.), we reduced our forecast," said LBBW oil analyst Frank Klumpp.




Oil Slips From 19-Month High as Ample Supply Offsets OPEC Cuts Blomberg Mark Shenk

Oil retreated from the highest close since July 2015 in New York as record U.S. crude inventories offset OPEC production curbs. Futures dropped 0.8 percent. U.S. government data showed stockpiles rose 564,000 barrels to 518.7 million last week, the highest level in weekly data going back to 1982. Still, it was the smallest gain this year and coincided with a drop in imports. The slowdown in the expansion may signal the output cuts by Organization of Petroleum Exporting Countries are starting to tighten supplies globally.

"It took a while, but there’s a realization that we have all-time, record storage and the market is reacting accordingly," Bob Yawger, director of the futures division at Mizuho Securities USA Inc. in New York, said by telephone. Analysts from Goldman Sachs Group Inc. to Energy Aspects Ltd. have said U.S. stockpiles were boosted by deliveries purchased before oil producers started cutting output in January. While the supply gain, which has kept prices in a tight range above $50 this year, slowed last week, Citigroup Inc. says the glut OPEC created by boosting production prior to the deal means they will need to prolong their cuts beyond June. West Texas Intermediate for April delivery fell 46 cents to close at $53.99 a barrel on the New York Mercantile Exchange. Prices rose to $54.45 on Thursday, the highest settlement since July 2, 2015. Total volume traded was about 36 percent below the 100-day average. Front-month futures advanced 1.1 percent this week. Brent for April settlement dropped 59 cents, or 1 percent, to $55.99 a barrel on the London-based ICE Futures Europe exchange. The contract climbed 0.3 percent this week. The global benchmark crude closed at a $2 premium to WTI.




Imports Tumble

U.S. crude imports fell 14 percent to an average 7.29 million barrels a day for the week ended Feb. 17, according to preliminary EIA data. Oil exports from the world’s biggest economy surged to a record and domestic production rose to 9 million barrels a day last week. American explorers boosted the oil rig count by five to 602 this week, the highest number since October 2015, according to Baker Hughes Inc.

"The rig count continues to go up and the U.S. continues to pump more," Mark Watkins, the Park City, Utah-based regional investment manager for the Private Client Group at U.S. Bank, which oversees $136 billion in assets, said by telephone. "At the same time OPEC has been pretty diligent about pulling barrels." OPEC and its partners achieved 86 percent of their agreed cuts last month, according to a statement on its website. The group’s Joint Technical Committee decided that producers “are on the right track towards full conformity” with supply cuts.




NewBase Special Coverage

News Agencies News Release 26 Feb. 2017

Losing 4.3 Billion Barrels Is Good For Exxon By Liam Denning

There's no denying that having almost one in five barrels of oil equivalent of your proved reserves slip off the books, as Exxon announced this week, isn't the company's finest hour.Coming just after Exxon took a $2 billion asset impairment, it looks like newly appointed secretary of state Rex Tillerson has left his successor as CEO some fixing to do.

Still, this is Exxon, and a big chunk of those lost reserves are still there in physical terms. It's just that, for example, the 3.5 billion barrels in the Kearl oil-sands operation in Canada no longer meet the SEC's criteria for being economic to produce anytime soon, chiefly because oil prices have collapsed (see this column from last year for more details on this).

Sandstorm

Trailing Canadian oil prices ended 2016 at $30, down 58 percent from two years ago

Note: Trailing 12-month averages.

So, as Exxon points out in its 10-K filing, higher prices could push those reserves back onto the books.




But even if the physical barrels are there, it's clear that reserves replacement, once a badge of honor for Exxon, has become a millstone. Here is how Exxon's reserves replacement fared cumulatively over the past decade, roughly coinciding with Tillerson's tenure as CEO:

Rise And Fall

Buying XTO Energy boosted Exxon's reserves replacement ratio but subsequent debooking sent it back down

Note: Cumulative reserves replacement over time. Reserves replacement equals net change in proved reserves divided by production.

The importance of acquisitions to keeping that ratio aloft becomes clearer once you strip them out (along with disposals):

Evaporating

Exxon's low organic reserves replacement in natural gas has been chronic, while progress in liquids was wiped out by the latest debooking.

Note: Cumulative organic reserves replacement. Calculated as net additions to proved reserves from revisions, improved recovery, extensions and discoveries, divided by production.

Tillerson chased the next big thing with his deals for XTO Energy Inc., which was badly timed, and in Russia, which suffered some bad geopolitical luck.




Overall, Exxon's reserves and production were actually lower in 2016 than in 2007, despite a string of growth targets set each year during most of the past decade. Even with lower output, reserves now cover only 13.1 years of production, down from 14.2 years in 2007 and a high of 16.9 in 2014.

Meanwhile, return on average capital employed -- again, a metric Exxon long favored as a measure of discipline -- in the dominant upstream division has fallen from 41.7 percent in 2007 to just 0.1 percent last year. And Standard & Poor's cited specifically the challenge of replacing Exxon's huge production when it cut the company's triple-A credit rating last year.

It is time for a reset.

The root of the problem for Exxon, and the rest of Big Oil, is an obsession with bigness. Focusing on finding ever more barrels, in ever more challenging places, led companies to invest awesome sums in new projects at the height of the boom, precisely when industry and asset inflation gave each buck progressively less bang. Doug Terreson, who covers the majors for Evercore ISI, summed it up in a report last October:

Investors correctly point to the $380 [billion] rise in capital employed but only a $140 [billion] increase in market value during 2008-2014 even before oil prices declined (Brent @ $100). Because companies did not heed the imbalance between capital formation and competitively advantaged investment opportunities and mistakenly equated volume for value, capital became stranded in unproductive areas.

In other words, like a tech investor in the late 1990s or a house-flipper in 2007, the majors lost their heads.

One reason they did was an expectation that oil demand and prices would only go up and to the right. If a combination of Chinese thirst and OPEC restraint (or dysfunction) were going to ensure triple-digit oil forever, then even high-cost endeavors like oil sands met the investment threshold.

As is now painfully obvious, an unexpected shale boom and existential questions about long-term demand for oil have cast considerable doubt on that view. Here, for example, is how the average economics of new oil-sands projects compare with North America's shale basins:




For the majors as a whole, there has been a growing disconnect between promises of ever-increasing dividends and bloated costs and capital expenditure budgets that swallow up cash but don't deliver higher production or decent reserves replacement. About half of Exxon's projects slated for 2018 onward, as detailed in its financial and operating review for 2015, consist of oil sands and liquefied natural gas, neither of which look great absent a sustained increase in oil prices.

Exxon has scored some successes in exploration of late, notably in Guyana, and has been buying its way into the Permian shale basin. It has also toned down its growth projections. These are good steps.

Exxon needs more, though. While its traditional premium to its peers has faltered somewhat of late, the stock remains relatively expensive, especially in light of the slide in return on capital:

Still Exxpensive

Exxon's aura has dimmed but it still commands a premium of 55 percent over its peers

Given much of that premium rests on Exxon's reliability, it shouldn't be taken for granted. After all, instead of owning Exxon, investors could instead own a basket of rivals such as Pioneer Natural Resources Co., Suncor Energy Inc., Valero Energy Corp. -- and maybe, within a year or so, even a bit of Big Big Oil, courtesy of Saudi Aramco's planned IPO.

So when Tillerson's successor Darren Woods takes the podium next week for his first Exxon analyst day as CEO, he should emphasize a decisive break with the past decade.Committing to keeping capital expenditure flat for the next few years would be one element of this, at least after the 14 percent jump Exxon has already indicated for this year.

As ever, M&A is a tool Exxon can use (especially with that relatively highly valued stock as a potential currency). That doesn't mean mega-deals, especially now that the recovery in oil prices has lifted the price of most big, needle-moving E&P targets. But it could mean pulling back in certain traditional areas like oil sands, swapping or monetizing them to expand in assets with better economics or more flexible production, such as more shale.

Above all, this should form part of a broader message: that being big is no longer the biggest idea out there. Access to profitable production providing cash for distributions, rather than reserves and growth per se, is what counts -- even if it means being flexible on traditionally non-negotiable things like, say, formal ownership of reserves.Exploring such options, at least, is warranted. Exxon's new chief shouldn't let a good setback go to waste.




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Khaled Malallah Al Awadi, Energy Consultant MS & BS Mechanical Engineering (HON), USA Emarat member since 1990 ASME member since 1995 Hawk Energy member 2010

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Khaled Al Awadi is a UAE National with a total of 25 years of experience in the Oil & Gas sector. Currently working as Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years, he has developed great experiences in the designing & constructing of gas pipelines, gas metering &

regulating stations and in the engineering of supply routes. Many years were spent drafting, & compiling gas transportation, operation & maintenance agreements along with many MOUs for the local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE and Energy program broadcasted internationally, via GCC leading satellite Channels.

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NewBase February 2017 K. Al Awadi




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