Or as ecologist Garrett Hardin succinctly put it: "You can never do just one thing."
]]> That's what the imminent startup of the reversed Seaway oil pipeline brings to mind. Its slated in-service date this week should alleviate backed-up crude volumes at Cushing, Oklahoma, and bring prices there more into line with those on the Gulf Coast. But it also leaves a new area of oversupplied, relatively lower priced crudes that bears watching: Midland, Texas.Oil produced from the Permian Basin in West Texas and southeast New Mexico, which is priced at Midland, is already valued below Cushing-priced crudes due to a tsunami of Permian output, observers say.
A wealth of geologic horizons to exploit and technologies that yield production efficiencies have turned the Permian into a horn of plenty oil-wise. But not enough infrastructure exists to take away all of the output galloping toward Midland. The result has been lower prices for those crudes.
"With pipeline capacity constraining booming Permian oil supply growth, Midland crude prices have blown out relative to WTI [West Texas Intermediate at Cushing], which itself is already heavily discounted" to Brent-priced crudes on the Gulf Coast, Deutsche Bank analyst Paul Sankey wrote in a May 14 report.
Seaway, with an initial 150,000 b/d capacity--rising to 400,000 b/d by early 2013 and 850,000 b/d by mid-2014--"may well exacerbate this discount, as it will alleviate oversupply at Cushing, but do nothing for the Midland bottleneck," Sankey said.
The WTI Midland-WTI Cushing crude differential reached just under minus $9/b on April 5, the widest since at least July 2001, according to Platts data. On May 14, it was minus $5.50/b.
Midland volume growth is "through the roof right now," Macquarie Securities analyst Chi Chow said. "There's limited capacity to move that crude to different markets."
Chow, citing Energy Information Administration data, noted that between January 2011 and February 2012, Permian production increased by nearly 350,000 b/d to 1.6 million b/d. EIA is the statistical arm of the US Department of Energy.
Market sources also expect Midland crudes to remain discounted to Cushing as Permian output continues to outpace takeaway capacity. "Even with Seaway coming online, you are still constrained coming out of the Permian into Oklahoma," one source said. "Rail [is] helping some, but not enough yet."
Seaway, which is expected to begin deliveries May 17, is a 50:50 joint venture between Enterprise Products Partners and Enbridge. The 500-mile pipeline runs from Freeport, Texas, to Cushing. The partners reversed the line so it can bring more oil to Gulf Coast refineries and alleviate what a few years ago became a bottleneck at Cushing caused by swarming crude volumes out of the North Dakota Bakken Shale and Canada.
In the end, the solution for Midland is more takeaway capacity, analysts said. Just as Seaway should relax price spreads between Cushing and pricier Gulf Coast crudes, so should planned pipeline expansions aimed at finding new homes for Midland-area crudes ease price imbalances there. Transportation plans include Magellan Midstream's reversal of the former Longhorn Pipeline that had run from Houston to Crane, Texas, and an expansion of Sunoco Logistics' West Texas Gulf line from the Permian to Longview, Texas.
That will bring Midland crude prices into better equilibrium with the Gulf Coast, although Permian producing keeps rising fast. In fact, given the dizzying pace that industry is finding new geologic plays in the US midsection, it may not be long before another price imbalance rears up--somewhere.
By the way, Garrett Hardin also coined the phrase "Nice guys finish last," and wrote an important early paper in the field of environmental geology called Tragedy of the Commons,. detailing the perils of self-interest even when innocent.
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The development of unconventional resources is the "biggest thing" BHP Billiton Petroleum Chief Executive Mike Yeager has seen in 33 years in the industry. "It's bigger than 2D to 3D seismic, it's bigger than shallow water to deep water, because it's going to double the hydrocarbons available to the world," Yeager told journalists on the sidelines of the southern hemisphere's largest gathering of oil industry executives.
ExxonMobil gas and power marketing vice president Emma Cochrane described "transformational change in energy and how it is delivered."
Cochrane reminded delegates of recent comments by the US oil and gas giant's chairman Rex Tillerson, who said the transformation unfolding in North America represented a "potentially decisive shift" in the history of energy.
"We may well be on the cusp of an epic rejuvenation of the energy industry not only in the United States and here in Australia, but around the globe," she said.
Saudi Arabian oil minister Ali Naimi was only slightly less upbeat. He told the conference that he saw the future of oil and gas as "less revolution, more evolution," but added that the industry was enjoying a period which offered "once-in-a-generation opportunities to both Australia and Saudi Arabia."
APPEA Chairman and Santos CEO David Knox extolled that it was "an exceptionally exciting time to be a part of the Australian oil and gas industry," which is in an "unprecedented phase of growth and expansion" with $170 billion worth of new LNG projects currently underway. On the east coast alone, the development of coalseam gas reserves for both the domestic market and for three sanctioned LNG export projects was "ultimately amazing wealth creation" for Australia, he told journalists.
According to Knox, just the speaker list at this year's conference was indicative of the buzz surrounding the industry.
"You've got Exxon speaking at this conference, you've got Chevron who are a massive investor in Australia, you've now got Christophe de Margerie who is one of the leading CEOs in the oil and gas industry. We've even had the Saudi oil minister!" Knox said. "There's a lot of interest in this country...the only questionmark is will we make sure that we create a stable investment climate."
The South Korean government can't be accused of not trying. The administration of President Lee Myung-Bak has been working very hard over the past year to lower gasoline and diesel pump prices and has come up with some creative solutions.
The fact that retail oil prices have continued to rise can only be attributed to the country's absolute dependency on imported oil, which makes it vulnerable to volatility in international markets. South Korea imports around 2.5 million b/d of crude, with more than 80% of that coming from the Middle East.
The four local refiners have been at the receiving end of most of the government's measures to cut prices. SK Innovation, GS Caltex, S-Oil and Hyundai Oilbank almost fully control the supply chain from production to retail through exclusive contracts with the country's 13,000 retail outlets, around 25% of which are directly operated by them.
The government has held refiners responsible for high pump prices and has accused them of acting as an oligopoly, even fining them for price collusion.
For their part, the refiners say pump prices are linked to international markets and follow global trends, a position that is supported by a closer look at the numbers. Retail gasoline prices in South Korea had increased by 4.7% year on year to Won 2,030 ($1.79)/liter at the end of March, according to data from state-run Korea National Oil Corporation. Over the same period, benchmark Mean of Platts Singapore 95 RON gasoline gained 11.76% to $136.46/b, or 86 cents/l.
In an effort to boost transparency and competition, Seoul earlier this year set up "discount" gasoline pumps and launched an online spot trading platform for oil products. There are currently 450 discount outlets in the country and the target is 1,000 before the end of the year.
These outlets are supplied by KNOC, which in turn buys fuel via tender from refiners and importers. More recently, the government signed an agreement with Samsung Total Petrochemicals to supply gasoline produced at its petrochemical facilities to the discount pumps. Samsung Total has until now been exporting all the gasoline it produces.
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Average gasoline and gasoil prices at the discount stations are around Won 35-40/l or 1%-2% cheaper than regular outlets, one energy ministry official said. But prices are expected to drop further once new fiscal incentives--mainly tax breaks for the discount outlets--kick in and Samsung Total starts supplies, he said.
The new online oil products spot market was launched on March 30, in theory providing a trading platform for the retail station owners as buyers and the refiners and importers as sellers. But daily trade has so far just been 81,000 liters of gasoline and gasoil, a tiny fraction of national demand of around 90 million liters.
The online market's poor performance has prompted the government to offer a tariff exemption on any imported products traded, compared with the 3% levy imposed on products sold in the regular market. Seoul also offered to refund Won 16/l of tax on imported products traded online and has eased regulations to boost imports.
Starting this month, oil importers are not required to maintain stocks equivalent to 30 days of imports and can qualify to import refined products as long as they have minimum storage capacity of 5,000 kiloliters (31,500 barrels), down from 7,500 kl earlier.
Prices on the online market have been Won 10-50/l lower than supply prices by oil refiners at regular outlets. "Online prices would be [further] lowered when more oil importers and refiners join the market," the ministry official said.
The government has also turned its focus on consumers and is planning measures to curtail rising demand. South Korea's products use in the first quarter of 2012 rose 1.2% year on year to 209.11 million barrels, according to KNOC, with gasoline use up 5.3% at 17.18 million barrels and diesel up 1.9% at 32.71 million barrels.
"The government has taken various steps to bring down retail oil prices, which have focused on suppliers, but the demand side should be addressed as well," one energy ministry official said. The measures, expected to be announced in coming weeks, might include regulations to lower oil demand for power generation and automobiles.
Critics meanwhile have blamed high taxes, which account for 45% of pump prices, and an export-oriented foreign exchange policy for the high domestic oil prices. Given any appreciation of the local currency, the won, would damage exports--which account for 53% of South Korea's GDP--the only viable choice appears to be a tax cut.
Oil taxes accounted for 14% of the government's revenue in 2010, however, and Seoul has ruled that option out.
"The government will consider lowering taxes on oil prices [only] if the price of Dubai crude stays above $130/b," a senior finance ministry official said recently. With Dubai now at $116/b, South Koreans might just need a higher oil price in order to pay less to fill their cars. --Mriganka Jaipuriyar in Singapore
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Under an order CFTC commissioners signed off on before a meeting Thursday, the effective date of many new derivatives regulations that Congress had ordered to be in effect by July 2011 will be pushed until the end of 2012. All the light that the clearing, reporting and position limits rules were expected to bring into the long, dark over-the-counter derivatives markets by now will remain off until probably next year.
But even early 2013 might be a stretch, according to Commissioner Scott O'Malia, who said Thursday that "unless the Commission focuses on its priorities, it seems unlikely we can meet this schedule."
The order, approved Thursday, is the third such order the agency has approved since it began its marathon rulemaking process just days after President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act into law in July 2010.
"I don't know of another agency that has worked so hard and accomplished so much," CFTC Commissioner Bart Chilton said this week.
But it's fair to say that commissioners had no idea when the process began how little would actually be accomplished by now.
Despite a frenetic work pace and, by all accounts, grueling schedule for CFTC staff, the agency is still less than two-thirds of the way through finalizing the more than 50 new rules mandated by Dodd-Frank. It's still unclear when final rules on margin, capital and swap execution facilities, among others, will be voted on and some key reforms, like the commodity position limits regime the agency finalized in October, have yet to be imposed.
Those limits are also being challenged in court by two major Wall Street lobbying groups.
In addition, some rules, particularly registration requirement for market players, may go into effect before margin and capital rules are finalized and the CFTC decides how the new rules will apply extraterritorially, or outside US borders, according to Commissioner Jill Sommers.
The CFTC seems to "have a penchant for putting the cart before the horse," Sommers said. "I am concerned that as we get closer to the finish line we may look back only to realize that no one is capable of crossing it."
On Thursday, O'Malia released a proposed schedule for finalizing rules through the fall. This includes, for example, finalizing core principles for swap execution facilities in July and finalizing the Volcker rule in the fall.
"I frequently hear from industry that the Commission's rules are not sequenced in a manner that provides them with the certainty they need to make budgeting, investment and hiring decisions," O'Malia said.
After Thursday's meeting, CFTC Chairman Gary Gensler told reporters, as he has done in the past, that the agency was not going to rush to get the rules done. The CFTC rules would be done right, in a balanced way and "not against a clock," he said.
Wrapping up day 1 of the Platts European Oil Storage Conference in Amsterdam was a panel of several of that day's speakers. Two subjects stood out in the discussion: the sad situation of European refineries, beset by closures and poor margins, and the opportunities to build storage in the Mediterranean. Here are a few of the key points made by some of the panelists, mostly paraphrased, but with some direct quotes.
]]> The MedMark Lewis, managing director for Europe at Facts Global Energy: If you look at the future of the Med, you can see increased crude supplies coming from the Caspian, and you have the potential at least for increased supplies from Iraq, which will use the northern pipelines from Ceyhan. Meanwhile, you have a vibrant, growing market in Turkey. As there is inevitability of growing products trade coming through the Suez Canal, when you go longer distances, you will tend to use larger tankers, because that will help carry a broader mix of products. Suezmax tankers increasingly will be used, so there are identifiable, significant changes, which will all tend to indicate the need for more storage facilities in the Med.
The Middle East will build more refineries. The products from them won't be going East, because Asia has enough refining capacity. So they therefore will send that product to the West. It's a long-term trend. It's not going to end next year or the year after. It's going to happen over the next 10 years, and that's the furthest any of us can look ahead.
(Responding to a question from the audience): It's not likely that we're going to see products put on ships from the Middle East and sailed around the Cape of Good Hope. Product tankers that are too big run into problems offloading at smaller ports that can't handle ships that big.
Rob Luijendik, managing director, TankTerminals.com: We do not see the Med as a coherent market. There is a European side, and there is an African coast, and there are large differences. There are a great number of countries on the northern border of Africa with their own mentalities and opinions. It is one of the most highly fragmented markets. There are also differences between the eastern and western Med countries.
You see some signs that international companies are showing interest in operating tanks and building up to get their foot in the door.
Given the enormous amount of world oil flows that go through the Black Sea and/or the Med, the amount of storage capacity in the Med market is out of relation to those flows. It is justified that more attention will be paid and that this market will be rectified. Things will change.
Europe's refining crisis
Chris Hunt, director general of the UK Petroleum Industry Association: There's a meeting on May 15 of key European energy ministers and other officials to discuss the status of Europe's refining sector. They need to start making some very swift decisions.
Even with all the focus on alternate fuels, by 2030, 80% of all transport fuels will still come from oil. The decision is where we want this oil to come from. Is it from an indigenous marketing base or imports? The latter would be great news for tank storage companies, but in terms of energy security, is this where you want to be?
More Lewis: The implication of closing these refineries is a question of whether we in Europe feel more secure importing crude or products. Generally around the world, countries have been more comfortable importing crude. China has made a strong decision that they will not be dependent upon product imports, and they are building refineries to ensure that doesn't happen.
We see the issue of dieselization as one of the major issues which is really undermining profitability in Europe. It was created artificially by governments, and for whatever reason, they encouraged diesel.
The EU has had chances to narrow the tax gap between diesel and the higher levies on gasoline, but have failed to do so. This has not been discussed at the EU level in any proper forum, and it's about time they did.
Addendum: In an email exchange with Mark a few days later, he expanded on his views that dieselization had hurt the European refining industry. Our view was that since diesel is the most profitable part of the barrel, why would a program that (we believed, incorrectly, according to Mark) ultimately encouraged the construction of more diesel capacity been damaging? Here's his response.
The problem with dieselisation is not a current issue but one that has been building up for 20 years or so. Essentially, the EU encouraged more diesel/less gasoline by tweaking the tax but the European refineries generally did not invest to match this change, relying instead on the convenience of exporting surplus gasoline to the USA and importing deficit diesel from Russia. The European refinery configuration has therefore been progressively getting further away from European demand pattern. It all worked fine until the US gasoline demand/imports fell and the European refiner couldn't dispose of its excess gasoline, which constrained runs, worsened the economics and still meant a shortfall of diesel. You can't put all the blame on the governments, the industry did not adjust to the changing local market but this would have required substantial investments in a sector which was already having to be invested in because of quality spec tightening (sulphur removal) and which was never making much money.
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Upcoming regions like Latin America and Africa held little interest for them because the trading volume was deemed too small. China is still the preferred buyer because it has a huge appetite and any company worth its salt has to trade with China.
However, for the Chinese, the buying mood was just not there. Chinese petrochemical producers and traders were a pessimistic lot after a lackluster first quarter. The key issue now is how to minimize losses over the rest of the year, rather than how to make money.
In Asia, aromatics prices have stagnated since March because of lack of demand from China. In April, Asian paraxylene hovered between $1,545-1,560/mt CFR Taiwan/China,benzene was range-bound between $1,175-1,185/mt FOB Korea and toluene was stuck at $1,210-1,220/mt FOB Korea. (Of course, crude prices have been doing largely the same thing. After trading near $125/b in mid-March, prices more recently have sunk toward $112/b.)
Traders with long positions have held their breath since February, hoping for a market rebound, based on the past history that the Chinese would resume their purchases after the Chinese New Year holidays at the end of January. In accordance with past practices, traders started to stock up on everything and hoped to reap profits in what they assumed would be a post-new year buying frenzy. Sellers also held on to their cargoes as they waited for news that the Chinese government would loosen credit and spur demand. After all, the Chinese operate on herd mentality: as long as one guy starts to buy, the rest will follow. Or so the saying goes.
But three months later, there was still no buying frenzy and getting credit from banks became more difficult for small-to-medium sized enterprises. These companies had to rely on third parties to obtain their letters of credit and pay a much higher interest rate than when borrowing from banks, as well as a 2% commission based on the total sum of the loan in order to buy imports. This has resulted in a widening price gap between imported and local petrochemical products. For polymers such as PVC and polyethylene, the price gap between domestically produced and imported cargoes ranges from $45-150/mt.
Another indicator of the moody domestic market can be seen in China's clothing industry. When the Europeans and Americans reduced their made-in-China purchases, local manufacturers decided to concentrate on the domestic market and started to increase their retail presence in the country. Unfortunately, it was a case of too much, too late.
In order to put their stamp on the market, they went on an aggressive expansion drive, setting up retail shops everywhere. But the domestic market was not as robust as expected and this has led to high inventory pressures for local clothing manufacturers. Chinese media widely reported that the warehouses of several top clothing manufacturers such as Shanghai-based Meibang Fushi and MBSKY, as well as Beijing-based VANCL were bursting at the seams. . Some of these companies were said to be holding more than eight months' worth of stock.
The result? A collapse in demand for cotton, polyester fiber, polyester intermediates and upstream aromatics feedstocks.
Monoethylene glycol inventory in China is said to be close to 1 million mt, and tanks in east China are filled to the brim. This is easily more than 10 times the inventory level of other aromatics products such as toluene or styrene monomer. Fellow polyester feedstock purified terephthalic acid, which hit a record high spot price of $1,528/mt CFR China on March 23 last year, became mired in negative margins eight months later.
Meanwhile, more than 10 million mt/year of new Chinese PTA capacity scheduled for construction this year was also delayed, and that sent the price of paraxylene--a feedstock for making PTA--spiraling down. PX hit a historic high of $1,815/mt CFR Taiwan/China on March 16, 2011 and there was huge expectation that prices would set a new high this year on the back of the new PTA plants starting in the first quarter. But since that didn't happen, PX has tumbled, averaging just $1,558/mt CFR Taiwan/China in April.
At an aromatics conference organized by JYD in Beijing in April, traders all wanted to know if there is a "sure-win" product this year. However, the answer given by industry experts was as bleak as the Beijing weather for anybody needing an increase in prices. "Just try not to lose any money," a speaker from Sinopec said. "The current situation is well beyond our control. The rich Chinese are not buying Chinese goods because they fear it is sub-standard and the poor Chinese have no money to buy. Until the macro climate improves, we can only wait and see."
]]>Floyd Wilson. former CEO of shale shamus Petrohawk Energy, has bet big that the answer is "yes." Just a few months into another hawk-themed corporate E&P venture, Wilson's new independent Halcón Resources is already mimicking the hawk its name was designed to reflect.
]]> Australia's BHP Billiton acquired Petrohawk last August for $15.1 billion. Six months later, Wilson and his team recapitalized the former RAM Energy, a small, privately held independent oil and gas company, and then financed a $400 million private offering.Now, with a capital cushion, a pending $1 billion cash-and-stock acquisition unveiled last month of still another company--privately held Houston-based GeoResources--and stakes in eight current plays to its credit, Halcón has already built an impressive nest of play targets.
Even though Petrohawk and Halcón share similar names -- halcón means "hawk" in Spanish -- and identical ticker symbols (HK), Halcón's current portfolio differs from its former incarnation in one important way: its thrust is oil rather than natural gas. Wilson said he expects Halcón's production to stay around 70% oil and natural gas liquids. Other than that, the philosophy hasn't changed much: like its predecessor, the new company aims to build itself as another force to be reckoned with in US resource plays.
And what a force it was. Petrohawk was the company that first introduced the Eagle Ford Shale to Wall Street in 2008. For those who haven't heard of it, the Eagle Ford is the prolific South Texas unconventional play with geologic properties and investment return rates that have nearly brought tears to oil company managers' eyes. Its total production is now galloping away at 500,000 b/d of oil, according to one industry source, and could jump to 1.5 million b/d by 2016, if energy consultants at Bentek Energy (a unit of Platts) are correct. Upwards of 230 rigs are currently drilling in the play, according to industry sources, a figure which has surpassed even the much-bragged-about Bakken Shale in North Dakota.
Even as successful an exploiter as Mark Papa, the CEO of EOG Resources -- the Eagle Ford's largest producer with 77,000 b/d of oil equivalent -- this week in a conference call dubbed the Eagle Ford the "800 pound gorilla that is developing into a 1,000 pound gorilla."
In any case, Halcón will acquire 24,000 net Eagle Ford acres in its GeoResources purchase, but the weighty
As it now stands, Halcón's portfolio also includes targets such as the Wilcox, a conventional Louisiana formation, and one conventional and two unconventional liquids plays whose sites were not disclosed.
Halcón's acreage also comprises the Woodbine, an East Texas play in its very early stages. Halcón in a presentation called the field "geologically analogous to the Eagle Ford," and said it couldbe developed on horizontal drilling.
In addition, Halcón has drilled one well and spudded a second on its concession in the Mississippi Lime, an Oklahoma-Kansas oil play in a mature field which is fast ramping up, and also has acreage in the emerging Utica Shale in Ohio and Pennsylvania.
So can Wilson do it again, and create another resource play powerhouse? His company's deck of assorted properties certainly appear flowing with potential, and its fledgling competitive claws are extended and have wasted no time in seizing opportunities to drill. Its managers show the same fierce, winged ambition that characterized Petrohawk. So it's a good bet that industry will be watching this exploratory bird of prey like a halcón.
Here's a quick summary of what's transpired in the past few days, based on reporting from a wide range of Platts' staff members: Takeo Kumagai, Pradeep Rajan, Mriganka Jaipuriyar, M.C Vaijayanthi and Charles Lee.
If there's one conclusion that can be drawn from these various reports, it would be this: earlier conventional wisdom that Iran would simply transfer the oil from cancelled EU sales into its Asian customers is looking woefully wrong. (A summary report of where events stood last week can be read here.)
]]> India: Iran already was becoming a less significant supplier to India. Officials have said that Iran was the country's fourth-largest crude supplier in fiscal 2011-12 (April-March); it was #2 the prior year. Average imports were 350,233 b/d, down 5.7% from the prior year.So with that fact behind him, Indian Foreign Minister S.M Krishna said Tuesday that while Iran is a key source of energy, India needs to look beyond the issue of its own energy
needs when considering its energy suppliers. As M.C. Vaijayanthi reported from Delhi, "Krishna's remarks mark a major shift in New Delhi's diplomatic stance on the Iran issue. Though Indian refiners have been cutting crude oil imports from Iran, the Indian government has publicly maintained that it will continue with its imports despite US financial sanctions imposed against Iran."
Japan: The latest development in Tokyo is that the Japanese government is looking into some way to help shippers who will continue to move Iranian oil after July 1. On that day, besides the EU ban on imports of Iranian oil going into affect, Japanese shipowners and charterers could lose the bulk of their insurance coverage as a result of EU sanctions taking effect that day. Japan will not be cutting off supplies from Iran. But the country's contractual volumes from the country are set to drop from slightly more than 300,000 b/d until end-March to around 240,000 b/d. Showa Shell, the biggest buyer of Iranian crude, and Cosmo Oil have renewed their contracts with NIOC effective in April, but at reduced volumes. But even those reduced shipments would be in jeopardy if shippers could not insure the tankers needed to carry the oil to Japan.
Meanwhile, like India, Japan reduced its intake of Iranian crude last year. Japan imported 279,000 b/d of crude from Iran in fiscal 2011-12, which ran through March. That was down 22.4% from a year ago, according to government figures.
South Korea: In late April, Charles Lee reported for South Korea that the country's refiners were likely to "sharply" reduce the amount of oil they were buying from Iran. Iranian oil accounted for 9.4% of South Korea's total crude imports last year. And in this year's first quarter, South Korea imported 17.70 million barrels of Iranian crude, down 22.4% from 22.81 million barrels it bought during first quarter last year. "The government has been in talks with the two refiners over how to cover shortfalls," an official told Platts, referring to SK Innovation and Hyundai Oilbank. "The talks are focused on seeking alternative supply from other sources. The government has placed a top priority on ensuring stable crude supplies."
China: There's no recent news about any Chinese plans to reduce Iranian supplies, as in the case of some other countries. But The Financial Times reported this week that Iran is accepting Chinese currency for some of the crude oil it supplies to China, partly as a consequence of western financial sanctions which seek to deny Iran access to international banking systems. China's crude imports from Iran in March fell 54.1% year on year to 1.08 million mt, or roughly 254,300 b/d, according to data from Chinese Customs. The imports represented 4.6% of China's total intake for the month. However, drawing conclusions from one-month swings in import figures can be misleading.
What's coming out: Despite all the statistics showing reduced purchased by several countries, Platts' Pradeep Rajan and Takeo Kumagai reported that Asian buyers of Iranian crude are sending tankers chartered by them to lift oil from the country's loading terminals, according to shipping sources and Platts ship tracking tool cTrack. As Platts reported: "Close to 13 crude tankers including VLCCs, Suezmaxes and Aframaxes have either loaded or are scheduled to load from Iran's oil-loading terminals on Kharg Island or Soroosh between May 1 and 17. Sources said most of these tankers were hired by various Asian oil buyers."
But about those reduced sales figures?: Pradeep also reported that Iran is believed to be storing up to 22 million barrels of crude oil and condensate on tankers offshore with a total of 15 tankers -- seven VLCCs and eight Suezmax vessels -- now anchored for more than 10 days near its loading terminals. On April 16, that figure stood at 16 million barrels.
And finally: International Energy Agency Executive Director Maria van der Hoeven said last week at the 13th International Oil Summit in Paris that Iranian exports had already fallen by 200,000-300,000 b/d because EU sanctions due to come into effect on July 1 were already affecting shipping and trade flows and are expected "to continue to decline in coming months." According to Platts' most recent monthly figures -- for March -- Iranian output has fallen to 3.4 million b/d from just under 3.6 million b/d last November.
]]>It's quite a turnaround. It's less than two years since the giant Leiv Eiriksson drillship headed back out through the Bosporus after a $200 million failure for Petrobras to strike commercial oil and gas off the Turkish coast.
]]> True, there had been some modest successes in shallow offshore waters, but the prize of a giant field in the sea's vast deepwater sections had consistently proved elusive, despite efforts by a cluster of companies from one end of Turkey's 1,000 km coast to the other.Now, there's not just hope, there's substance. That comes from the successful Domino-1 well drilled for ExxonMobil and Romania's Petrom at the Neptune East block, where results announced in March disclosed a 70.7m gas horizon and estimated recoverable reserves of between 1.5 and 3.0 trillion cubic feet. This is not large by world standards, but the point is that it is considered by analysts as the precursor to finds at five nearby structures.
That's certainly the view of Mark Beacom, vice president of Sterling Resources, which made a useful gas discovery is shallow waters off Romania in 2008 and which considers the development of facilities for its own production as the basis for a larger network serving other fields as well.
In a rhetorical flourish of the kind beloved by conference openers--and Beacom was delivering the first address to the annual conference of the Balkan and Black Sea Petroleum Association last week--the Sterling VP began by saying: "Is the Romanian Black Sea ready for success? The answer is yes."
To Beacom, the first step is development of its own Ana and Doina discoveries. "These are ready to go," he said. "We discovered and appraised them in 2008. It's a $500 million project, 10 bcm of gas. The concept is two platforms to serve as a hub, not just for Ana and Doina but for other projects that will come along, and a 110-km pipe back to shore."
Moreover, Beacom added, "we have other blocks to suggest there is quite a lot more production to come along."
Finding 10 bcm of recoverable reserves is scarcely a major discovery. But Beacom noted, "we look at this and see the kind of structure that Exxon's been chasing, so we think there's a lot more there. There's a horseshoe of other concessions around us, so, from wellhead to burner tip, we are going to put in place a road map that's going to make it a lot easier for others to follow in our footsteps."
So convinced is he that development will be rapid, he even goes so far as to argue that by 2016, Romania could actually start exporting gas.
Then there's the expected tenders. Dr. Volodymyr Ignashchenko, counsellor to Ukraine's Minister of Ecology and Natural Resources and member of the country's PSA Inter-Agency Committee, told the Vienna conference that tenders for the 12,600 sq. km Skifska area (Ukrainian geologists have estimated recoverable reserves at 80-100 million tonnes of oil equivalent there) and the 7,000 sq. km Firosa area (estimated reserves: 135-150 mtoe) are expected in mid-June. There should be considerable interest, not least since Skifska is separated only from Neptune by a tiny strip of water which is not included in any current tender arrangements.
What's more, Ignashchenko said the PSA terms would be "very favorable," adding: "Up to 70% of the production is for compensation and of the remaining 30%, up to 80% is for the company." However, he added, "we will request a very significant signature payment, around $200 million to $300 million."
For its part, Bulgaria, too, already has some offshore tenders out, issued last month. Kiril Temilkov, the CEO of the country's gas transit company Bulgar TransGaz, told Platts that awards should be made sometime in June.
Hans Hutta, an academic analyst on Black Sea prospects, noted that to the south, ExxonMobil's Neptune field ran adjacent to an area of high Bulgarian prospectivity.
Just what will happen next will depend on drilling programs. But both ExxonMobil and Sterling have plans for fresh drilling in 2013 and this should help ascertain whether Purvin and Gertz, which carried out a major study in 2011 (before the Domino One discovery,) was close to the mark when it predicated the development of a Romanian offshore industry on the basis of the potential existence of a 600 bcm offshore resource.
It's that study that prompted Beacom to argue that a 600 bcm resource base could result over the next decade in capital expenditures of $30 billion and operating expenditures of $25 billion, together with tax and royalty receipts of $45 billion.
True, Beacom went on to highlight a host of problems that have yet to be resolved, notably Bucharest's 'made-in-Romania' gas price whereby domestic gas is priced at less than a third of gas imports.
But with Romania formally committed to EU regulations to deregulate the gas industry -- and because of the fact that its current stance constitutes a breach in its obligations to the IMF concerning disbursements of major IMF loans -- Beacom assumes there will be major price reforms.
]]>April turned out to be a significant month for the future of Russia's offshore oil and gas sector as Moscow loosened its grip on the vast riches expected to be found in the country's mostly unexplored waters.
Not only did the Kremlin announce a raft of tax incentives for future exploration and allow more companies -- including private firms and international operators -- to gain access to offshore blocks, but state-controlled Rosneft finalized two huge strategic offshore pacts with US major ExxonMobil and Italy's Eni.
Rosneft also invited four of its Russian peers, Lukoil, TNK-BP, Surgutneftegaz and Bashneft, to join it in a number of exploration projects.
It seems that by opening the doors to all-comers, the penny has finally dropped for Moscow that it would not be able to develop alone offshore fields to compensate for plateauing output at its traditional onshore producing regions.
On April 12, Vladimir Putin announced the new measures aimed at boosting activity in Russia's offshore which, he said, would hopefully attract investment of as much as $500 billion in the country's waters over the next 30 years.
Putin said the new tax incentives would be kept unchanged for 15 years, allowing companies the freedom to make investment decisions that, at least in theory, they would not live to regret given a traditionally capricious Kremlin.
Russia has a history of changing its tax regimes to suit the country depending on macroeconomic conditions. But the pledge to keep tax conditions unchanged until 2027 could reassure would-be investors.
"The 15-year guarantee is encouraging but we're yet to see if the government fulfils its obligations," said Valery Nesterov, an analyst at Moscow-based investment bank Troika-Dialog. There are examples of where Moscow has kept its promises though, he said, pointing to the success of negotiations over production sharing agreements, which although protracted, overcame a number of hurdles.
"After all the trouble PSA projects saw in Russia, they are intact and have already reached recoupment point," Nesterov said.
But there have also been instances of sudden changes to legislation when the authorities amended fiscal conditions for projects in order to fill the state's coffers. The cancellation of tax incentives for the major Vankor field in East Siberia was the most recent example, he said.
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Russia already has one, very high-profile offshore project--the mighty Shtokman gas and condensate field in the deep, inhospitable waters of the Barents Sea. The project's shareholders include Norway's Statoil and France's Total.
Confusion remains though over whether the field will be allowed to benefit from the new tax incentives as the government said it would take a separate decision for the giant field.
The government may be reluctant to grant wide-scale tax breaks for Shtokman as it wants to attract new investors to Russia's offshore projects and boost exploration activity in the hostile region, said Maxim Moshkov from UBS. Shtokman is already an established project, with 3.9 trillion cubic meters of gas reserves and known investors.
What Moscow really wants is to attract investment for projects with high geological risk, said Nesterov. The authorities estimate that Russia's offshore regions contain reserves of around 100 billion mt of oil equivalent, of which some 70%-80% is gas.
"But the reserves data is unreliable and further geological work can change the picture drastically," he said. "Russia needs to obtain as much as possible data in the next five to seven years -- the scale of the necessary investment is enormous," he added.
So with Total, Statoil, ExxonMobil and Eni already firmly based in the Russian offshore, and Bashneft, Lukoil, Surgutneftegaz and TNK-BP readying themselves to join the offshore club, the only question remains who else may come forward?
Could we see offshore specialists such as Shell, Chevron, the UK's BG Group, Brazil's Petrobras and China's CNOOC looking to partnerships with Rosneft and Gazprom in new offshore projects?
Analysts think this will depend largely on the success of ExxonMobil and Eni. "I think that other companies will watch carefully to see if [ExxonMobil and Eni's] cooperation and relationships with Rosneft are successful. If so, we will likely see more interest from other international companies," Constantine Cherepanov from UBS said.
But potential investors may not have too much time to decide. Rosneft President Eduard Khudainatov spoke passionately of how quickly the company had acted with relation to the tax changes. "You see how the world has been set on fire by the decision on a favorable tax regime to stimulate development of the [Russian continental] shelf?" Khudainatov said after signing the strategic cooperation deal with Eni. "Other partners will have to speed up, and take their decisions quickly.
--Nadia Rodova in Moscow and Stuart Elliot in London
]]>The oil and gas industry appears to be waging this same battle internally, judging from comments over the four-day course of the OTC that wrapped up May 3.
]]> Several speakers brought out the idea that the energy is becoming more of a technology industry, evoking the mindset of Apple and of the late Steve Jobs -- although maybe that topic is just en vogue this year. The conference was optimistic to the point of being futuristic."Look at your iPad," said Eamonn McCabe, vice president of oil and gas development for Australia's Woodside Energy, in a talk about offshore production of the future. That is the "essence of great design. That is what we want things to look like."
Other executives talked about what they want things to feel like -- not always a topic broached at oil conferences.
Shell's Robert Patterson, vice president of upstream projects, said the oil and gas industry should "inspire people to reach beyond" and "provoke a sense of curiosity."
Sounds nice, but there sure were a lot of clunky, non-Apple sleek pieces of equipment in the 641,350 square feet of exhibit space. The oil industry has always been a rodeo, with the blood, and the mud and beer. Does it really need to change? Can it? Or would it be like putting a shiny, sleek case on a Motorola DynaTAC?
"It's got to change," said Bill Joiner, an SMU professor who heads the executive education department and designs programs for the energy industry. "You have to create a new culture" for the industry to both keep up financially and technologically and to attract the best workforce, he said.
The offshore industry is going to need more geeks, as remote monitoring, the crunching of vast steams of data from well sites and even unmanned platforms become common. But "getting IT folk into the oil and gas business isn't as easy as you might think," McCabe admitted.
But maybe it's just because they didn't check out the "Tools for Studs with Big Nuts" booth along with the 89,400 in attendance -- a 30-year record -- this last week. There is always next year.
]]>Twelve years ago, when Arnold was 25 and at Enron, he was described by an Enron executive as responsible for trading one-third of the US gas market each day.
Arnold had an unusual knack for trading. He rarely showed up in public but did go before the CFTC shortly after the Dodd-Frank bill was passed to explain that the one thing he objected to most was position limits.
With trading margins so low, the thrill of the trade had apparently gone for Arnold.
Energy commodity traders from a well-known financial institution told a number of Platts editors the other day that they are seeing hedging activities "drying up" because of low prices. They said gas producers who typically would have 75% of their 2013 and 50% of their 2014 production hedged at this point, today have zero hedged. They mentioned Chesapeake as a case in point.
The trading business, which includes managing companies' hedges, is already consolidating, the traders said.
Power generators that are supposed to be mopping up some of the excess gas and thus giving the price a boost are in fact using more gas and generating slightly more electricity this year than last. But their revenues, due to very low power prices, are in the doldrums.
Calpine, a Houston-based merchant generator with a large fleet of gas-fired turbines, had a 52% increase in the amount of power it generated in the first quarter of 2012 compared to the first quarter of 2011. But because of low power prices, it saw a 17.5% drop in its year-over-year quarterly revenue.
The Dallas-based holding company Energy Future Holdings, which is desperately trying to service $31 billion of debt it took on when it bought the utility TXU in 2007, lost just over $300 million in the first quarter. EFH reported operating revenue of $1.22 billion in the first quarter, compared with $1.67 billion in the first quarter of 2011. The decline in revenue was due, the company said, to both lower retail and wholesale power sales and lower electricity prices.
Low power prices are eating into the margins of companies responsible for building much of the US wind generating capacity. As a result, the lower margins are having a knock-on effect on the debate in Washington over the 2.2cent/kWh production tax credit that has gone to wind developers, but is due to expire at the end of this year.
To get financing to build a wind farm, a developer must have a long-term power purchase agreement with a buyer to show bankers they will have a steady revenue flow from which to repay loans.
The power prices embedded in those PPA's are heavily influenced by $2.00 MMBtu natural gas, as no buyers want to be seen making a long-term pledge to purchased "overpriced" power.
For companies like Horizon Wind Energy, the problem is the opposite: the risk of agreeing to sell power for 20 to 25-years at too low of a price.
Horizon, which has built 27 wind farms and owns, operates and maintains 3,600 MW of capacity in 10 states, explained recently that the sale price of power embedded in 20 to 25-year power purchase agreements with off-takers has been coming in at about the 3 cts/kWh range, compared with four or five times that price just 2 years ago.
At those low prices, and without the 2.2ct/kWh production tax credit, many of the deals don't make sense.
Horizon, along with NextEra Energy Resources, which has built 8,500 MW of wind in the US, has said that if the credit is not extended by Congress it will not build wind farms in the US next year. Instead, it may turn its attention to big utility-scale solar projects that are eligible for a 30% investment tax credit that is good through the end of 2016.
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