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26 июля 2012, 19:30

Renewable energy developer looks first to transmission as a key

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One of the challenges facing renewable energy growth in the United States is geography. The strongest wind is found smack in the middle of the country, between the Rockies and the Mississippi River. Yet the biggest population centers are hundreds of miles away.  A Houston-based energy company says it has the answer: high-voltage direct current lines. Imagine a long-distance highway with an on-ramp and off-ramp. Renewable electrons can hop onto this expressway and then exit at the end of the line to power homes and businesses.   The company behind this vision is Clean Line Energy Partners. The company is led by Michael Skelly, a wind industry veteran, and Jimmy Glotfelty, a former Department of Energy official during the last Bush administration.   It is a win-win situation, they say. More wind farms will get built, allowing more customers to switch away from fossil fuels.   One proposed transmission line, for example, would run from western Oklahoma to Memphis. That project promises to deliver 7,000 megawatts from one of the windiest corridors in the country to the southeast, a region lacking any significant wind or solar installations to date.    So what's standing in the way?   First, building new transmission lines is never easy. Developers must navigate a bureaucratic maze to obtain all necessary permits, and gather the community support needed to overcome opposition.   There is also the matter of cost. New transmission lines are billion dollar projects.   Ratepayers usually foot the bill. But Clean Line's proposal said it can avoid that pitfall by incurring the costs instead. To recoup these expenses, Clean Line plans on selling capacity to companies utilizing the transmission lines.   And that is where the rub lies. There aren't yet wind farms around the interconnection points.   Of course, Clean Line executives believe that will change. As its transmission projects move through the development stages and momentum grows, renewable energy developers will begin building the necessary wind farms, they say.   That might sound like a shaky assumption in light of the generally bearish view toward the U.S. wind industry today.     But Skelly and Glotfelty remain optimistic, arguing their planned transmission lines offer enough value to overcome the costs. These benefits include:   --Southeast utilities can import green power, arguably a less expensive option than trying to build renewables themselves.    --Grid operators can more easily balance the bulk electric network. The addition of renewables, like wind, causes a headache for power engineers who must deal with fluctuating output.   One solution would be diversity: integrate wind resources from places with different weather conditions. A pair of proposed transmission accomplishes that goal by linking the Great Plains with Illinois and Indiana.        --Help California meet the state's mandatory renewable targets. A proposed DC line from New Mexico to Southern California increases wind power available to utilities.   The numbers being discussed here are huge.   All four transmission lines would have enough capacity to carry some 17,500 megawatts at any given time. To put that in perspective, wind turbines currently supply as much as 48,000 megawatts, so these new lines can carry more than 25% of all wind-generated capacity.    As a note of caution, however, the list of failed transmission projects is a long one. Will Clean Line simply add its name to that list? Or will it one day manage to sink steel in the ground?   Tweet

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26 июля 2012, 00:00

EIA analysis: US gasoline stocks jump as supply climbs, demand drags

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US gasoline stocks jumped 4.134 million barrels last week, as production and imports rose, while demand remained lackluster, EIA data released Wednesday showed. The gasoline data was not entirely bearish, however, as US West Coast stocks fell for the second week in a row. You can read Platts analysis of it here. Tweet

25 июля 2012, 13:40

Middle distillates clearly taking center stage in the oil market

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The attention of the market is starting to turn to the middle of the barrel. Two reports this week brought home the squeeze in distillates. It's particularly notable because while the public and the political class, particularly in the US, focus on the price of gasoline, market experts know that a spike in the middle distillates is far more likely to occur than one in gasoline, where demand in the biggest consuming country--the US--continues to slide. The market may have gotten a bit of bearish news late Tuesday, when the American Petroleum Institute data reported that US distillate stocks rose by 2.6 million barrels, which is more than analysts had projected. Also, runs in the US are pushing toward the 94% level, and a lot of that is because distillate cracks are so strong that refiners are trying to maximize returns by producing as much as they can. Here's the key number: total distillate stocks in the US are now about 20 million barrels less than they were in mid-July last year, and about 40 million barrels less than at this time in 2009 and 2010. The last time they were this low--at somewhere between 120 million and 125 million barrels--was right after the all-time high of the 2008 price spike, which many analysts still consider to have been driven primarily by diesel, not crude speculation. Energy economist Philip Verleger, in his weekly Notes at the Margin report, paints a picture of low stocks that could be read as bearish. He compares the levels of today to 1985, right before the Saudi-driven price collapse of that year, and sees similarities. "This behavior (of marketers holding low stocks) is not unusual," he wrote. "We saw it 27 years ago. In 1985, well-informed marketers held stocks far below normal levels as they worried about an impending price collapse." Which of course is what happened, as the price of WTI slumped from more than $30/b to briefly drop below $10/b on April 1, 1986, the ultimate April Fool's joke for those who were long. Verleger publishes a data series called returns to storage, which is calculated by using the forward curve. It determines the rate of return that comes from buying oil today, putting it into storage and sold now for future delivery. Negative returns to storage coincide with a backwardation, and that condition is now prevalent in the distillate market. In the Verleger database, he said, "we have never seen returns this low for the December contract in mid-July. Product inventories on the US East Coast are, in short, very low." A similar warning was heard in a report put out by Bank of America Merrill Lynch on Tuesday. "Unless European and Asian refineries turn runs up sharply and unless the heavy draw on US supplies from Latin America eases up, inventories will likely not build to adequate levels for this winter," the report said. It added that the supply situation in the US Atlantic Basin, including Europe, was "precarious." The bank's report projected that refiners could increase runs, and based on recent data, that's exactly what is happening. But the report also expressed concern that it would be "too little, too late" for the winter. The Atlantic Coast ULSD crack spread relative to Brent has been a gold mine for refiners. Based on a comparison of Platts' assessments for US Atlantic Coast ULSD and dated Brent, the crack spread averaged $16.23/b from April 1 through the end of May. But it's been $18.99/b since June 1, and since July 1, the average is $19.22/b.  Tweet

24 июля 2012, 20:00

Non-passage of oil bill threatens Nigeria's oil sector

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Nigeria's long-awaited Petroleum Industry Bill is set to finally see the light as it moves its way through to Parliament, but its delay has taken a toll on the nation's economy. The bill is a crucial piece of legislation which addresses everything from reconfiguring the corrupt-ridden state oil company, fiscal regimes, deregulation of the downstream industry and domestic gas utilization. Most of the contentious issues over the fiscal terms have been resolved. However, there are concerns about staffing during the transition process, the sanctity of contracts, and industry officials question making confidential contracts public. Licensing rounds, contract renewals and billions of dollars worth of investments have been stalled over the last five years while the PIB languished in parliament. Crude production, the mainstay of Nigeria's economy, has declined over the last three years, having never come close to the government's 4 million b/d target for 2010. The lack of clarity on regulations has encouraged multinationals like Royal Dutch Shell and ConocoPhillips to set their sights elsewhere. Shell has offloaded some of its onshore operations to focus and finance offshore expansion, which is less risky in terms of the Niger Delta insecurity. ConocoPhillips plans to sell off its assets in Nigeria, including a 17% stake in the Brass LNG project and offshore and onshore blocks. It is suspected that the group's decision to quit Nigeria will further delay the final investment decision on the two-train, 10 million mt/year Brass project, slated for the first quarter 2013. The delay in the passing of the bill had already stalled Gazprom's proposed $2.5 billion investment aimed to provide gas for the ramshackle domestic power sector. Long-time West African producers like Nigeria may also face stiff competition from East Africa, where significant oil and gas reserves are attracting billions of dollars in investment from the world's largest energy companies. Cove Energy paid $11 million for assets in East Africa just three years ago and could now fetch as much as $1.9 billion as a five-month bidding war between Shell and Thailand's PTT for the company draws to a close. Its major prize is an 8.5% interest in an offshore Mozambique gas  field considered one of the biggest in the world. The bill has become synonymous with missed deadlines. The latest draft will not be debated until after September 27 when lawmakers return from holiday. Swift passage can be ruled out as legislators scrutinize clause by clause in an onerous task that is likely to take several months. Much has been made of its status as Africa's top exporter of oil and its potential to grow its production capacity, but failure to pass the bill will thwart Nigeria's potential.   . Tweet

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24 июля 2012, 19:03

The mad, mad world of merchant power, through the histories of NRG and GenOn

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In the late 1990's the brilliant idea emerged of breaking apart electric utilities to spur competition. For the most part, electric utilities were local or regional monopolies comprised of a batch of power generation facilities that sold electricity to their captive residential and commercial customers over their transmission and distribution lines. The idea for the power sector that stemmed from the deregulation movement under Ronald Reagan was to hive off the generation portion of the utilities and let new, so-called merchant generators be set up by anyone who wanted to build new facilities and sell into a wholesale power market. New retail companies would compete with each other for customers and buy the wholesale power. The wires would essentially be left alone. It's been a wild dozen or so years for the broken-apart utilities, but an even wilder period for the merchants.  I use the word "wilder" in the latter case as a substitute for the word "disastrous." I say that for this reason:  On Sunday, NRG Energy and GenOn, two merchants, announced they were merging.  And as one who has covered both companies for some time, I couldn't stop thinking what they both have been through ever since Enron collapsed. First, the merger of two merchant firms comes at a time when many in the industry are listening with fascination to the testimony being given the North Carolina Utilities Commission on how, and why, the Duke Energy board tried to get out of its merger with Progress Energy. These are not two merchant firms, but two utilities that own other utilities, and to hear how Duke's board waited until the day the merger with Progress was in effect before it fired its new CEO who was from Progress, left lots of people wondering, "what the hell?"  The NRG/GenOn deal also takes place as one of the original merchant firms, Dynegy, seeks to exit bankruptcy. NRG was founded as the merchant arm of Xcel Energy and went through its own bankruptcy in 2004. Many of the original merchants, such as PG&E NEG, which was liquidated in a Chapter 7 bankruptcy in 2004, ran into serious debt problems after borrowing heavily to build large amounts of natural gas-fired capacity. For example,the purest merchant, Calpine, which owns just over 27,000 MW of natural gas-fired capacity, went into bankruptcy in 2005 after natural gas prices soared to over $12/MMBtu. Calpine is now out of bankruptcy, and suffering not from high gas prices but rather very low power prices. In October 2005, NRG -- once out of bankruptcy -- bought Texas Genco, which gave it Genco's 14,000 MW, including the 2,600 MW South Texas nuclear facility, for $5.8 billion.  It bought the generation from a private equity consortium made up of The Blackstone Group, Hellman & Friedman, Kohlberg Kravis Roberts and the Texas Pacific Group, that had paid $2.8 billion for it only one year prior. The consortium was backed by Goldman Sachs financing. Texas Genco was the group of generation assets in the Houston area that were spun off from the utility Houston Industries, later renamed Reliant Energy, when the Texas market was deregulated in 1999. NRG not only bought the generating assets, but in March 2009 it bought Reliant Energy's retail electricity unit for the modest sum of $285 million. Reliant Energy had no generation, and it had lost its credit support when Merrill Lynch was folded into Bank of America. So through its merger with GenOn, NRG goes almost full circle with former Reliant assets, almost reconstituting the old Houston utility.  GenOn was created after Mirant, the former merchant arm of Southern Company, exited from bankruptcy and decided to merge with RRI Energy, the former merchant arm of Reliant Energy, in a $1.6 billion all-stock deal. RRI was the merchant firm Orion that was created by Goldman Sachs and Constellation that was bought by Reliant in October 2002 for almost $6 billion in borrowed money. Reliant spent two years trying to restructure that debt, and lost out on the chance to buy back its Texas Genco assets when its bankers, led by Goldman, ruled it out. Mirant, of course, would come out of bankruptcy and take its own shot at buying NRG.  In May 2006, Mirant launched an unsolicited $7.8 billion bid for the company, which was halted less than two months later when a hedge fund, owning just 1.6% of the shares, said Mirant should put itself on the auction block instead. Meanwhile, in late 2008 and into July 2009, Exelon made its own failed $7.5 billion attempt to buy NRG, which NRG's CEO David Crane consistently and successfully fought off. Then in August 2009, Dynegy and privately held merchant LS Power undid a merger they had done in 2007. A year later, The Blackstone Group sought to buy Dynegy and sell off some of its generating assets to NRG to help pay for the deal. Blackstone eventually withdrew its $4.7 billion offer when Dynegy shareholders, led by billionaire investor Carl Icahn, pressed for a higher price. With no buyer around, and suffering  from low power prices, reduced revenue and relatively high debt, Dynegy eventually did what all good merchants have done: file for bankruptcy.   Tweet

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24 июля 2012, 04:03

The mad, mad world of merchant power

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In the late 1990's the brilliant idea emerged of breaking apart electric utilities to spur competition. For the most part, electric utilities were local or regional monopolies comprised of a batch of power generation facilities that sold electricity to their captive residential and commercial customers over their transmission and distribution lines. The idea for the power sector that stemmed from the deregulation movement under Ronald Reagan was to hive off the generation portion of the utilities and let new, so-called merchant generators be set up by anyone who wanted to build new facilities and sell into a wholesale power market. New retail companies would compete with each other for customers and buy the wholesale power. The wires would essentially be left alone. It's been a wild dozen or so years for the broken-apart utilities, but an even wilder period for the merchants.  I use the word "wilder" in the latter case as a substitute for the word "disastrous." I say that for this reason:  On Sunday, NRG Energy and GenOn, two merchants, announced they were merging.  And as one who has covered both companies for some time, I couldn't stop thinking what they both have been through ever since Enron collapsed. First, the merger of two merchant firms comes at a time when many in the industry are listening with fascination to the testimony being given the North Carolina Utilities Commission on how, and why, the Duke Energy board tried to get out of its merger with Progress Energy. These are not two merchant firms, but two utilities that own other utilities, and to hear how Duke's board waited until the day the merger with Progress was in effect before it fired its new CEO who was from Progress, left lots of people wondering, "what the hell?"  The NRG/GenOn deal also takes place as one of the original merchant firms, Dynegy, seeks to exit bankruptcy. NRG was founded as the merchant arm of Xcel Energy and went through its own bankruptcy in 2004. Many of the original merchants, such as PG&E NEG, which was liquidated in a Chapter 7 bankruptcy in 2004, ran into serious debt problems after borrowing heavily to build large amounts of natural gas-fired capacity. For example,the purest merchant, Calpine, which owns just over 27,000 MW of natural gas-fired capacity, went into bankruptcy in 2005 after natural gas prices soared to over $12/MMBtu. Calpine is now out of bankruptcy, and suffering not from high gas prices but rather very lower power prices. And in October 2005, NRG -- once out of bankruptcy -- bought Texas Genco which gave it Genco's 14,000 MW, including the 2,600 MW South Texas nuclear facility, for $5.8 billion.  Funds for that deal came from a private equity consortium made up of The Blackstone Group, Hellman & Friedman, Kohlberg Kravis Roberts and the Texas Pacific Group. Texas Genco was the group of generation assets in the Houston area that were spun off from the utility Houston Industries, later renamed Reliant Energy, when the Texas market was deregulated in 1999. NRG not only bought the generating assets, but in March 2009 it bought Reliant Energy's retail electricity unit for the modest sum of $285 million. Reliant Energy had no generation, and it had lost its credit support when Merrill Lynch was folded into Bank of America. So through its merger with GenOn, NRG goes almost full circle with former Reliant assets. Think of the mercurial character in the "Terminator 2" movie whose liquidized "Cyborg" falls to the ground in pieces when blasted apart, only to slowly coagulate back into its former form.  GenOn was created after Mirant, the former merchant arm of Southern Company, exited from bankruptcy and decided to merge with RRI Energy, the former merchant arm of Reliant Energy, in a $1.6 billion all-stock deal. RRI was the merchant firm Orion that was created by Goldman Sachs and Constellation that was bought by Reliant in October 2002 for almost $6 billion in borrowed money. Reliant spent two years trying to restructure that debt, and lost out on the chance to buy back its Texas Genco assets when its bankers, led by Goldman, ruled it out. Mirant, of course, would come out of bankruptcy and take its own shot at buying NRG.  In May 2006, Mirant launched an unsolicited $7.8 billion bid for the company, which was halted less than two months later when a hedge fund, owning just 1.6% of the shares, said Mirant should put itself on the auction block instead. Meanwhile, in late 2008 and into July 2009, Exelon made its own failed $7.5 billion attempt to buy NRG, which NRG's CEO David Crane consistently and successfully fought off. Then in August 2009, Dynegy and privately held merchant LS Power undid a merger they had done in 2007. A year later, The Blackstone Group sought to buy Dynegy and sell off some of its generating assets to NRG to help pay for the deal. Blackstone eventually withdrew its $4.7 billion offer when Dynegy shareholders, led by billionaire investor Carl Icahn, pressed for a higher price. Suffering from low power prices, reduced revenue and relatively high debt, Dynegy eventually did what all good merchants have done:  file for bankruptcy.

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23 июля 2012, 21:12

Chinese oil demand: Back to the level of last September

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Chinese apparent old demand declined in June, according to Platts' analysis, a long way from the high-flying double-digit, year-on-year growth levels of just a few years ago. You can read about the decline, and the sharp turnaround from the growth rates of the past, here.

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23 июля 2012, 19:56

Regulation & The Environment: the Saudis are going green

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The many words out of the Middle East about turning to renewable technologies and cutting carbon emissions are turning into concrete actions, as Tamsin Carlisle discusses in this week's Oilgram News column, Regulation & The Environment. -------------------------------------------------------------------------------------------------------------------------------------- Middle East governments are rolling out ambitious renewable energy programs, even as austerity measures hamper such development in Europe.  Among the latest signs of an apparent mass Arabian conversion to environmental activism is Saudi Aramco's July 8 launch of a clean-energy venture capital arm. "Saudi Aramco Energy Ventures (SAEV) represents a significant step forward in our corporate transformation to become the world's leading integrated energy company with innovation as a key attribute," Saudi Aramco CEO Khalid al-Falih said in a statement. The OPEC kingpin is not the first Persian Gulf oil exporter to propose a strategic shift toward green technologies. That laurel goes to Abu Dhabi. In 2008, it started building a carbon-neutral community, Masdar City, set state renewable energy targets and created the $250 million Masdar Clean Tech Fund. But when the CEO of the world's biggest energy company makes an explicit strategy statement, the world needs to sit up and listen. A glance through Saudi Aramco's recent press releases show the powerful state oil company means environmental business. In July alone it launched SAEV, pledged to plant 1.2 million mangrove trees along the Saudi coast and set aside land for the region's first eco-park--at Ras Tanura, near its Persian Gulf oil export terminal. In June, the company announced a desert wild-life preserve. In March, it launched an oilfield water recycling program. In February, Saudi Aramco sponsored the First Saudi Renewable Energy Conference and Exhibition at King Fahd University of Petroleum and Minerals, heralded as "a platform for a new start-up in the concept of renewable technology." "Not only does the company hope to utilize the best technologies to bolster its status as a key global competitor, but it intends to develop and produce such technologies as well," said public affairs manager Nasser al-Nafisee. This could all be green wash, but consider that the biggest buyers of Saudi crude are Asian countries which are not always squeamish about the environment. An element of me-too-ism cannot be ruled out, as smaller Arab nations have led the region on environmental issues. The UAE, which includes Abu Dhabi, was the first Gulf Cooperative Council state to outlaw natural gas flaring at refineries and oil fields and to announce plans for commercial-scale carbon capture and storage; and the UAE hosts the secretariat of the UN International Renewable Energy Association (IRENA) at Masdar City. ------------------------- Meanwhile, Qatar was the first GCC state to join the World Bank's international program to reduce flaring; the tiny emirate has done more than any other oil exporter to make natural gas, as LNG, an internationally available alternative to higher-carbon fuel oil and coal. In May, Qatar's deputy prime minister and long-time former oil minister,,Abdullah al-Attiya, took the chair of the next conference of Parties of the United Nations Convention on Climate change, to be held in Seoul at the end of the 2012. One of his recent acts was signing up Qatar as a founding member of the Seoul-based Global Green Growth Institute. Oman, the smallest GCC oil exporter, has quietly taken notable steps to use renewable energy technology to power oil and gas production. As one example, state-controlled Petroleum Development Oman (PDO), a consortium that also includes Royal Dutch Shell as a major partner, is developing the world's first commercial-scale solar-powered oil development with California's GlassPoint. Nonetheless, the scale of recent Saudi green initiatives is too large to be dismissed as copy-cat policy. In May, for instance, state-sponsored King Abdullah City for Atomic and Renewable Energy unveiled firm plans for a massive 41 GW of installed Saudi solar power capacity by 2032. Much clean-energy development in the GCC is being driven by enlightened self-interest. All GCC states except for Qatar are short of natural gas for power generation and industry. They are urgently seeking viable alternatives to burning gas for steam-generation as they turn to exploiting heavier crude and re-injecting ever more associated gas into mature oil fields to enhance crude output. Most GCC states are also striving to diversify their electricity supplies away from oil and gas-fired generation in order to maximize oil exports. In particular, Riyadh hopes to eliminate the need to burn as much as 800,000 b/d of Saudi crude in summer for power generation. Sensible plans to integrate renewable energy with the region's traditional oil business is a sign of the GCC energy sector coming of age. In the long run, supplementing fossil fuels with energy from low-carbon sources could prove more effective in curbing global carbon emissions than stuttering Western policy drives that have failed to force a premature end to the petroleum age. -- Tamsin Carlisle in Dubai   Tweet

21 июля 2012, 01:33

The oil industry's lure of the deep (waters)

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If you thought 2008 was a heyday for deepwater drilling, you ain't seen nothin' yet. At least that's the message suggested by the first two drillers, Noble Corporation and Diamond Offshore, that reported second-quarter earnings this week. While earnings were healthy, it was the commentary by the drillers' managers that made Wall Street sit up and take notice.  Both companies say they expect the global ultra-deepwater segment to carry the ball for them going forward. And that "forward" looks pretty darn good. Between bidding rounds this year in places as diverse as Tanzania, New Zealand and Colombia, planned marine seismic surveys and new discoveries in places both familiar (such as the US Gulf of Mexico and West Africa), and not so familiar (such as Kenya and Liberia), a lot of drilling is going to need doing in the next few years. An already tight rig market that has driven up demand due to continued exploration successes worldwide over the last couple of years has pushed up typical rig dayrates near the $600,000 mark. While that isn't a record--some time back, ExxonMobil inked a deal for $703,000/d for an expensive state-of-the-art ultra-deepwater floater--today's rates in the high-fives are an average. Recently at least one deal was inked for well over $600,000. And earlier this year, Morgan Stanley analyst Ole Storer predicted that later in the year, rig rates could climb to $714,000/d. But oil and gas finds really tell the story. So far this year, upstream operators have made 22 announcements of oil and natural gas discoveries in water depths of 4,000 feet and greater, compared to 37 such discoveries in all of 2010, Simon Johnson, vice president of marketing and contracts for Noble, said during the company's earnings call July 19. The average water depth of the finds is 6,400 feet, although the deepest this year so far is offshore Mozambique in 7,400 feet of water. Those finds will all need to be appraised and developed, meaning more drilling. And then produced. And after that, they will need more drilling to keep up production, necessitating more drilling still. It adds up to a whole lotta rig-years. And each new discovery adds to the need for rigs. The newest ultra-deepwater rigs coming into the market these days are equipped to drill in 10,000 feet of water, and can gear up for waters 12,000 feet deep with some added equipment. The most state-of-the-art rigs can also drill 40,000 feet below the mud line. That is well past current needs; the deepest well ever drilled so far in the US Gulf, for example, lies in about 10,000 feet of water and the deepest total depth has been about 35,000 feet. And so far, 10,000 feet is about the water depth limit of US areas now open to leasing.   But ultra-deepwater--loosely definfed as water depths of 7,000 feet and greater--isn't the only market segment doing well. Deepwater--again, loosely defined as water depths around 4,000 to 7,000 feet--also is doing well. Michael Acuff, senior vice president of contracts and marketing for driller Diamond, said rigs for that class are fetching dayrates in the high $400,000s to low $500,000s. And even the midwater market for rigs that can drill in no more than 1,000-4,000 feet of water is performing well, and dayrates there also continue to increase, he said. For example, Diamond revealed this week that the midwater Ocean Vanguard, confined to work in waters no deeper than 1,500 feet in Norway, was signed to a 20-month extension with Statoil for $450,000/d. That is "higher than our forecast of $300,000/d and its prior dayrate of $352,000/d," UBS analyst Angie Sedita said. But that relatively high rate may not be all that surprising, given that the number of such rigs is limited. Most were built during the mid-1970s to the early 1980s when 1,500 or 2,000 feet was considered the ne plus ultra in water depths. But drillers today aren't building rigs that can only navigate 2,000 or 3,000 feet of water; they are chasing customers that are chasing what ultra-deepwater Gulf operator Anadarko Petroleum called the "big boys" in complex subsalt reservoirs which are found in 6,000-plus feet of water, not to mention five or six miles under the sea.  Even while ultra-deepwater garners all the recent attention, midwater depths do continue to lure operators to areas of the North Sea and Gulf of Mexico where infrastructure is abundant, well costs reasonable and smaller independents can get a leg up on offshore expertise. In fact, even ultra-deep players such as Anadarko at one time were major midwater operators; Anadarko still has producing fields there, for example, the Nansen-Boomvang fields, in the US Gulf's East Breaks area in 3,600 feet of water.  One thing is certain: be it mid-, deep- or ultradeep waters, offshore looks set to be a bright star in a universe with room for a lot of ingenuity and success. Tweet

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20 июля 2012, 11:58

July PX Asia contract price fails to settle, shows disconnect between traders, end-users

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The Asian paraxylene contract price for July was left in limbo as PX producers and downstream purified terephthalic acid makers failed to reach an agreement. The ACP monthly negotiation is led by four PX producers -- ExxonMobil, JX Nippon Oil and Energy, Idemitsu Kosan and S-Oil -- and six PTA makers -- BP, Capco, Mitsui Chemicals Corp., Mitsubishi Chemical Corp., Oriental Petrochemical (Taiwan) Corp. and Yisheng Petrochemicals.  Only one PX producer -- Japan's Idemitsu -- settled the July price with its buyers at $1,160/mt CFR. ExxonMobil was said to have settled at $1,275/mt CFR with Mitsubishi even though it had already revised its nomination price down to $1,200/mt from the initial $1,300/mt. Even though the ACP would sometimes fail to settle fully, the July price was extremely contentious because spot prices had shot through the roof when negotiations broke down on June 29. Between the settlement date of June 29 and July 19, PX went up by $174.50/mt or 14%, settling at $1,413.50/mt CFR Taiwan/China. Compared with Idemitsu's settlement at $1,160/mt, the difference was $253.50/mt or 22%, the widest margin ever between a producer's settlement and the spot price. PTA makers were understandably upset. While PX manufacturers have seen production margins of at least $300/mt since 2011, PTA producers' margins have been falling since November last year. From June 29 to July 19, PTA makers saw their production margins worsen from minus $16.74mt to minus $70.91/mt.  End-users blamed the rise in PX price on "inter-trades" as traders rapidly bought and sold cargoes among themselves, driving up the spot price with each transaction. Many producers in China, South Korea and Taiwan cut their operating rates or shut their plants for maintenance while new PTA plants were delayed as production margins deteriorated.  On July 17, Yisheng Petrochemicals, the world's largest PTA maker, sold off its feedstock in protest against soaring spot prices but its action failed to dent the market. While traders felt that the price rally reflected the supply/demand fundamentals, end-users were enraged because they said current prices had no connection to the ground realities. "We are producers. Raw materials make up the bulk of our operation cost but traders don't have such concerns," said a Chinese PTA maker. "They just want to buy low and sell high," he added. While there has always been an element of speculation in spot trades, PTA makers had been more tolerant in the past when everyone along the polyester chain was making money. "If there's money to be made for everyone, that's fine. But PX traders are now grabbing huge chunks off us rather than taking small bites. How are we to survive?" he lamented. Chinese PTA makers also tend to be integrated with downstream polyester plants. With the economic downturn in Europe, demand for made-in-China clothes has fallen sharply as well, affording PTA makers no respite.  In retrospect, PTA makers could have just accepted the July ACP at $1,200/mt CFR and all would be well. But the PX ACP has been higher than the spot price sine February and so PTA makers wanted to push the contract price lower in the second half of the year. "I don't blame the PTA negotiators for standing their ground because their intention was to ensure that we survive for the rest of the year," said a PTA maker who was not part of the ACP negotiation process. Instead, traders had to take responsibility for the current impasse, he said. ACP negotiations, which usually end on the last day of the previous month, were actually extended by more than a week in July. As spot prices rallied, PX producers were reluctant to settle at their final nomination of $1,200/mt CFR. In the absence of an ACP settlement, producers will fall back on the Platts monthly spot price, which is currently at $1,358/mt CFR. They also do not have to supply the full contract volumes to their buyers and were able to sell more cargoes in the spot market, fueling more trading activity.Tweet

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20 июля 2012, 01:11

Taking California's low carbon fuel standard, and making it national

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"I've never heard anybody come up with a definitively better approach." That statement by Daniel Sperling wrapped up the first of three presentations he and other mostly academics are making in Washington this week to launch a push for a national Low Carbon Fuel Standard. It's a clear statement of confidence in his plans, which is not surprising; as a member of the California Air Resources Board, Sperling, who is also a professor at the University of California-Davis, is one of the key backers of that state's own LCFS. So now he and his colleagues from various universities and foundations are trying to push for a national LCFS. There are some differences and similarities with the California version, but just the fact that it would be a national standard raises some questions that don't need to be addressed on a state level (e.g., interstate commerce), just like California gets to avoid some tricky issues since it's only a state initiative (e.g., rolling out an LCFS nationally.) Sperling made his cocky comment in declaring that an LCFS does two things concurrently: it increases US energy security by incentivizing transportation fuel alternatives, and it reduces carbon emissions. Nothing else works as well, he said. One key point that Sperling made: a national LCFS would not replace the US renewable fuel standard, which mandates increasing levels of biofuels in the US transportation energy mix through the rest of the decade and into the next. "We see the political realities," Sperling said, referring to the strong backing that renewable fuel standards get from agricultural interests. So the LCFS would be "appended" to the RFS, according to Sperling. But it's clear that Sperling and his committee don't think all that much of the RFS. It doesn't permit a lot of choices, and it doesn't permit much competition, he said, specifically directing very fixed levels of usage of a small number of alternative fuels, such as corn-based ethanol (which employs heavy land use and is not particularly efficient); sugar-based ethanol (high energy efficiency, but in a market protected by import tariffs or domestic US price supports); cellulosic ethanol (which doesn't exist in commercial quantities); or biodiesel (which is expensive.) By contrast, Sperling said, an LCFS "doesn't pick winners. It isn't too narrow." It encourages anything from ethanol to electricity. In the policy design recommendations released by the study's contributors a day before the introductory sessions commenced, the architects suggested five broad ways that gasoline and diesel producers could meet national standards. Based on other statements in the report and at the information session, here's how the LCFS backers may see these five guidelines working. --Reduce the carbon intensity of gasoline and diesel. Under the California LCFS with every crude carrying its own public carbon intensity (CI) rating, refiners shunning the higher grade levels in favor of lower CI-rated crudes would be moving toward this goal. --Increase the use of alternative fuel blends in gasoline and diesel. Blending 2% or 10% biofuel into heating oil, for example, would be a step in this direction. --Substitute lower-CI for higher-CI biofuels in blends (for example, substitute low-carbon ethanol for corn ethanol). That's easier said than done with a tariff on sugar-based ethanol in place, but a lot easier if cellulosic ethanol ever becomes a commercial reality. --Sell more alternative fuels, like E85. This has been noted by others as probably the quickest way to get to RFS standards pushing up against the conundrum of a rising fixed level of required ethanol use, declining gasoline usage and a 10% blendwall that can be cracked, but not without encountering a whole lot of issues. --Purchase credits from other regulated parties. This is very clearly a key facet of the California law, and the backers also see it as central to a national LCFS. But even though those five steps are somewhat specific, Sperling kept coming back to a central argument: innovation will drive the solutions. But there won't be innovation to a significant degree, the LCFS backers believe, unless there is a national low carbon standard that must be met. "We can't predict how this innovation is going to develop," Sperling said. "The marketplace will lay things out in interesting and exciting ways." In other words, necessity is the mother of invention. In one pointed back-and-forth, an audience member said it "takes a lot of arrogance to think that innovation can be scheduled," coming in rapidly enough to ensure that overall prices to the consumer won't rise while an LCFS is being implemented. "I think it's arrogant to think that innovation wouldn't occur," Sperling shot back. Several representatives from groups such as the American Fuel and Petrochemical Manufacturers and the American Petroleum Institute were in attendance. One question put to the panel: if the US has an LCFS, and other nations do not, wouldn't that simply result in a "shuffling" of crudes, where high-carbon crudes get exported from the US to countries without a low carbon standard, low-carbon crudes come to the US, and the impact on overall global carbon emissions is zero? The response demonstrated the LCFS authors' belief in the credit system and innovation. They believe innovation will drive so much reduction in the carbon intensity of transportation fuels that the price of credits will be so low that a US-based refiner, for example, might choose to pay the hit for credits and process high-carbon crude. It would be cheaper than incurring the cost of shipping crude from or to distant markets. You can see the group's Policy Decision Recommendations here. What the group calls its Technical Analysis Reports is here. A full list of all the institutions involved in the two-year study is in both reports. Tweet

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19 июля 2012, 01:43

US oil refineries, cranking away...except on the Atlantic Coast

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The US Energy Information Administration released its latest oil data report Wednesday, and included in this report were regional averages of refinery utilization rates. Although analysts polled by Platts Monday were slightly off, expecting the average national run rate to increase to 93.1% of capacity, run rates at 92%--what the EIA reported for last week--mark a break in a trend where recent run rates have been approaching levels not seen in the US since a 93.6% run rate back in July 2007. But back in the summer of 2007, the economy was on cruise control. US petroleum demand, measured by the EIA's "product supplied figure", was just above 21 million b/d. Last week, petroleum demand was 18.5 million b/d. Obviously, economic prospects are not quite as rosy these days. Refinery runs are also being lifted by exports. While the most precise data lags by about two months or more, the EIA's most recent weekly export data--which is always heavily subject to revision--showed US total exports recently running just under 3 million b/d. While the weekly numbers have cracked 3 million b/d a few times earlier this year, the recent numbers are some of the highest on record. (In summer 2007, the figure was closer to 1.2 million b/d). Clearly, US refiners are maintaining strong levels of output. Last week, runs were above 90% throughout the US, with the exception of the beleaguered Atlantic Coast. So why are refinery run rates so high? And why are they high everywhere but the Atlantic Coast, the region that arguably sets the marginal price of gasoline by being both a region of higher than average demand, as well as home to the delivery point of the NYMEX RBOB futures contract? Atlantic Coast refining runs have room to grow, despite a recent shaving of operable capacity. At 82% of capacity last week, Atlantic Coast run rates were 0.7 percentage points above year-ago levels. But last year, capacity was 430,000 b/d greater, at 1.618 million b/d, before various shutdowns intervened. Comparatively, run rates for US Gulf Coast refineries last week averaged 94.2% of capacity. Midwest refineries averaged 93.8% , West Coast refineries averaged 90.9% and Rocky Mountain refineries averaged a whopping 97.5%. Even though the Rockies represent a very small segment of the sector as a whole, the number is about as close to 100% as this data is likely to ever get; there's always a problem somewhere, even if minor. US refining margins have been strong enough for quite a while now to encourage higher runs. The Gulf Coast Light Louisiana Sweet cracking margin, for instance, averaged $16.69/b last week, according to Platts data and Turner, Mason & Co. yield formulas. Refining margins in the Midwest have greatly outpaced Atlantic Coast margins over the recent past, helped in part by higher Canadian imports and US shale oil production out of the Bakken, backing up at the NYMEX trading hub in Cushing, Oklahoma. Midwest WTI cracking margins have skyrocketed recently, averaging just over $30/b for June 2012. Comparatively, Midwest margins averaged $23/b in June 2011 and just $7/b in June 2010. While margins averaged $10/b in June 2009, they were negative for the the month of June 2008. Meanwhile, USAC Bonny Light refining margins have averaged $12/b over the same period in 2012. Going down the line, USAC Bonny Light margins averaged around $5/b for June in each of 2011, 2010 and 2009, and averaged just over $1/b for June 2008. Things haven't changed; the recent margin improvements in the Midwest can be attributed to cheaper crude streams such as Canadian imports and Bakken shale oil, created both by higher production and logical constraints that's keeping plenty of crude locked in the Midwest, even after the recent Seaway reversal. Further, over the past few years both Midwest and Gulf Coast refinery owners have made significant investments in upgrading their coking capacity so that they would better suited to profit from running heavier crudes. They have, in essence, optimized their refineries to handle a wider variety of crude oil inputs. So what happened with Atlantic Coast refineries? It's basically a case of foregone investment in lieu of choosing light, sweet crude imports from places like Nigeria. Instead of reinvesting in expensive additional coking capacity, as many refiners in the Midwest and Gulf Coast have done in order to process cheaper heavier crude streams, USAC refiners chose to save the money, and bet they could maintain margins on light, sweet imports like Bonny Light. And it must have seemed like a wise move to investors at the time: why lay out billions in costly upgrades when international oil markets reflected an increasing trend toward more US imports of light, sweet barrels. But that was hit by the shale revolution, with Atlantic Coast refiners needing to compete against product coming out of refineries benefitting from cheaper crude; a tight North Sea market that has driven up the price of Brent relative to other crudes;  and the collapse in European demand, which put more gasoline into the export market. However, it does not explain why airlines like Delta and private equity firms like Carlyle are in the market. That is fodder for another story, but clearly these groups believe they can get a leg up on weak Atlantic Coast refining margins by bringing supplies of crudes such as Bakken to the USAC. Tweet