Headline News
March 4, 2008
Quarterly Biofuels Survey Sees Proposed Ethanol Capacity Drop
As ethanol companies continue to grapple with high feedstock costs, there appears to be "a leveling off of corn-based ethanol build-out," according to a recently released survey by Soyatech on its latest quarterly Biofuels Index.
During the last quarter of 2007, U.S. ethanol production capacity increased by approximately 407 million gal/yr, to 7.322 billion gal/yr, representing a 6% growth from the previous quarterly index. However, proposed ethanol capacity for those plants under construction decreased by 344 million gal/yr (a 5.4% decline), to 6.011 billion gal/yr, while approximately 577 million gal/yr of capacity in planning (that is, expected ethanol capacity from future facilities) was either cancelled or suspended, the Biofuels Index noted.
"While some of this reduction in capacity in planning was due to projects moving from the planning phase to construction, there was also a significant amount of planned capacity that was explicitly cancelled or postponed, approximately 675 million gal/yr," the Index noted.
"We are circumspect about the numbers for total planned [ethanol] capacity, as it is very easy to announce plans," said Jacob Golbitz, director of research for Soyatech and its parent company, HighQuest Partners. "Additionally, some groups that have suspended or cancelled their plans have not made those decisions public. As a result, we believe that there is 'phantom capacity' reflected in these numbers,"
he added.
A handful of ethanol projects have been halted or suspended in the past six months, citing feedstock corn prices that are consistently hitting new highs over $5/bu. Among the more high profile, VeraSun announced it was suspending construction of its 110-million gal/yr ethanol plant in Reynolds, Ind., but the suspension could be lifted later this year, "depending upon the return of more favorable market conditions."
For biodiesel, total online biodiesel capacity increased approximately 202 million gal/yr during the quarter -- an 11% growth -- to 2.033 billion gal/yr. While approximately 239 million gal/yr of biodiesel production from facilities under construction was dropped during the quarter -- a 17.5% decrease -- biodiesel capacity from planned facilities saw a 210 million gal/yr gain during the quarter, representing a 9.7% increase, the Index noted.
"Approximately 173 million gal/yr of biodiesel capacity in planning was explicitly cancelled in Q4, which was more than offset by the 306 million gal/yr in new planned capacity announced during the quarter," the Biofuels Index noted.
U.S. biodiesel production is also going through growing pains. Its production and blending economics have been unfavorable for some time. With high feedstock costs, mostly due to soybeans, many biodiesel producers have been pulling
back on output or sending more than half of their product to Europe. However,
it should be noted that the Biofuels Index tracks production capacity and not
actual production.
For more information, visit www.soyatech.com.
February 28, 2008
RFA Chief: Ethanol Still Growing, Fighting Critics
Orlando -- The U.S. ethanol industry "is bringing about revolutionary change," propelled by the expanded renewable fuels standard (RFS), but there are still several challenges that can be overcome and opponents that need to be proven wrong, Renewable Fuels Association (RFA) President and CEO Bob Dinneen said here today, during the association's opening conference session.
During his annual "State of the Ethanol Industry" address, Dinneen outlined the economic and environmental benefits the ethanol industry has contributed to over the past year, as well as the large production and consumption growth the fuel has seen. "Ethanol is now a ubiquitous component of the U.S. motor fuel supply, blended in more than 50% of the nation's gasoline, and will very soon be in virtually every single gallon of gasoline sold from coast to coast and border to border,"
he said.
On the production side, 29 more ethanol plants were brought on line in 2007, increasing annual production capacity by 32%, to 7.9 billion gal/yr. An additional 60 ethanol plants are under construction, with another seven plants expanding, which will add 5.5 billion gal/yr of capacity, he added.
But despite this growth, as well as the expected production of commercially viable cellulosic ethanol in the near future, "[s]ome have questioned whether you are capable of meeting the aggressive targets established by the new RFS, calling it a 'bridge too far,'" Dinneen said. "One oil company representative recently ridiculed the RFS schedule, questioned our logistics capabilities and besmirched ethanol's environmental record. But let me tell you, I have confidence in the people in this room. ... I know that cellulosic ethanol production is closer than conventional wisdom believes, and I know the targets established in the energy bill will be met," he added.
Last year saw the emergence of the "food versus fuel" debate, where some questioned whether there is enough corn both to feed the world and be a blend component in the world's fuel. But Dinneen and others speaking at today's conference said those concerns just aren't warranted. "The chattering class of naysayers ignores that ethanol biorefineries produce both fuel and feed, that we only process starch, leaving the high feed value protein to be marketed to livestock and poultry," Dinneen said. "This past year, the U.S. ethanol industry produced more than 14 million metric tons of high quality distillers feed. Taking the fallacy of food versus fuel to a contrived conclusion, some argue insistently that rising corn prices are at the heart of increased consumer food prices," being blamed for higher milk, beer and bread prices, he noted. But high energy costs are to blame,
he added.
There also is a debate on the land-use impacts of growing corn for ethanol. "[R]ecent analyses assume it will all come in the most environmentally sensitive parts of the globe, wreaking havoc on ecosystems and eliminating any potential greenhouse gas benefits biofuels might otherwise provide," Dinneen said. "These analyses ignore the complexities of the land use debate" and do not take into account increases in corn yields, he noted. "Corn yields averaged 150 bushels per acre last year. But with improved technology, we will see 300 bushels per acre long before we see a bulldozer pulling into Yellowstone National Park with a permit for biofuels production," he added.
"It is time to pull together and get the story straight," National Corn Growers Association CEO Rick Tolman urged the more than 2,200 conference attendees. "It is a great story that is not being told and in fact, it is being perverted" by those in the media, he noted. Like Dinneen, he touted the corn efficiencies that have been seen in the number of bushels per acre, as well as the increase in the number of ethanol gallons produced from a bushel of corn. "We can do food, feed and fuel," he added.
A biofuels source speaking to OPIS on the sidelines of the conference echoed some of the same concerns outlined by Dinneen and Tolman. Now that the
ethanol industry has a much higher profile than it did several years ago, "I think
we are going to be under a lot more scrutiny [on these issues] in the future," the source noted.
February 26, 2008
Gasoline Jobbers to Weigh Benefits of Ethanol Splash Blending, RIN Trading
Gasoline jobbers in the U.S. should think twice about jumping into splash blending ethanol-blended gasoline themselves, Ron Marr, a consultant with Lake Erie Biofuels, told OPIS on Monday.
This was even though jobbers could potentially save some money from cheaper ethanol and gasoline prices and make profits from trading Renewable Fuel Identification Numbers (RINs).
Marr cautioned that the high administrative and accounting cost for keeping track of RINs could outweigh the favorable splash-blending economics.
The issue of RINs was thrust into the spotlight in January when the value of RINs shot up significantly in response to speculation and short-covering.
RIN values in February remain relatively high in comparison with levels seen late last year, but the market stabilized somewhat after the buying frenzy in January fizzled out.
Despite the cautionary note on splash-blending economics and RIN trading, some ethanol marketers are quick to point out that the auditing and compliance cost would be more than covered by savings from cheaper ethanol prices over the course of a year.
A RIN is a 38-character ID number assigned to every gallon or group of gallons of renewable fuel, which includes ethanol and biodiesel.
At the point of sale from the producer, the buyer will track the numbers through the blending and scale of the product, and report each purchase and sale to the Environmental Protection Agency (EPA).
This RIN can be traded or kept for a year, and refiners will purchase RINs to offset the renewable fuels requirement as set forth by the Energy Act of 2007.
For every 100,000 gallons of gasoline refined in 2008, a refiner must have 4,666 RINs in their possession, Marr said.
A RIN is assigned a "1" as the first number when produced. When the gallon of fuel is blended, a "2" is the first digit meaning unassigned or separated. The unassigned RIN can be traded or sold.
Marr said that a jobber or end-user does not have to register with the EPA to blend because the ethanol and renewable fuel can be bought from a renewable fuel marketer without RINs attached.
The jobber can still take the ethanol credit as if he were registered, but must fill out multiple IRS forms, he said.
If a jobber wants to keep the RINs, register with the EPA, sell or trade or have the flexibility in buying ethanol, he must perform an annual "Attest Audit" in which a Certified Public Accountant (CPA) or other EPA defined person conducts an audit
of the RIN transactions and write a letter to the EPA attesting to the accuracy,
Marr said.
Estimated cost for the audit was $5,000 for the first year.
Georgia-based ethanol marketer Strategic Bio Energy LLC said that larger jobbers and end-users have the bureaucracy to handle the administration and accounting for RINs.
The ethanol marketer is pushing an ethanol top-off service to distributors who make a second stop.
The company also promises to hedge fixed price purchases so that marketers can take advantage of what has been a trend since mid-2007: purchasing ethanol on a forward basis, giving blenders product at a discount to the prompt market.
Jobbers could buy ethanol from marketers with RINs attached or without
RINs attached.
"Smaller companies should just use us," said company director of business development Chris Curro.
"They will be able to get the savings from the ethanol and we will take care of the RINS for them and split the revenues realized from the sale of RINS."
He said that some jobbers would buy ethanol with RINs and some without.
"You would only have to sell 100,000 gallons of gasoline in a year to pay for the CPA," Curro said. "That is even if you did not make anything on the RINS."
Curro explained that the conservative estimate on the average pool margin improvement by blending with ethanol is $.05/gal.
February 21, 2008
Sharp Ethanol RIN Price Spike Changes Fuel
Blenders' Strategies
The sharp price jump in ethanol- and biodiesel-use credits known as Renewable Identification Numbers (RINs) have prompted fuel blenders in the Midwest to pick up the trouble to track, report and possibly trade this lucrative commodity, some industry sources said on Wednesday.
Just a month or two ago, some blenders in the Midwest were willing to pay or paid a premium for their ethanol supplies to avoid the hassle of tracking, reporting and auditing the RIN accounts.
However, the whole RIN trading ball game changed in January when the value of RIN shot up several folds in a span of a week due to shortcovering and speculation.
"We have heard Midwest blenders paying a premium of 2-3cts/gal for their (ethanol) supplies without RINs attached only a few months ago, but it is not the case now," said Dawn Carlson, president of Petrolem Marketers & Convenience Stores of Iowa.
"It is now the opposite. Blenders want their RINs now."
Until recently, ethanol producers were benefiting from charging a premium for their sales without RINs to blenders, and at the same time, they could sell those RINs in the market for more profits.
In early February, trading activity and prices stabilized in February as most buyers covered their short positions ahead of the approaching deadline on Feb. 28 to turn in the RINs for the volumes imported and exported in 2007.
This week, RINs for 2007 are mostly stable at about 3.25cts/gal of ethanol, compared with a high of about 5cts in late January and 30pts in early January. RINs can be stripped and resold, and RINS are traded in batches of 1 million gallon.
RINs for 2008 are offered at 4cts/gal.
The RIN is a 38-character numeric code generated by renewable fuel producers and importers, and it is assigned to batches that they transfer to others.
RINs form the basic currency for credits, trades and compliance in the RFS program, which was initiated in September 2007.
Although RIN prices have stabilized after spiking in mid-January, it is still significantly stronger than late last year and early January.
When the RIN prices reached a high of 5cts per RIN in mid-January, a trader importing a 300,000-bbl gasoline cargo had to pay about $25,000 for RINs to go along with his cargo. This was compared with $1,519 in early January.
February 19, 2008
RFS Standard Already Limiting Fuel Choices
Last week's decision to require that U.S. gasoline supply contain at least 7.76% renewable fuel has already has some ramifications. Southeastern supplier Colonial Oil told customers this week that it would not be able to provide both E10 and conventional blends of gasoline at some racks.
Colonial was the first supplier to roll out E10 in Savannah, Ga., but it kept all conventional blends available as an option. Customers just learned that effective April 15, the company will only be able to provide E10 blends at the terminal.
"We truly regret the necessity of this drastic move, but we have no reasonable alternative under the federal government's mandate that ethanol comprise 7.78% of our gasoline sales for 2008," customers were told.
The company will also go to strictly E10 blends in Charleston, S.C., effective April 15. Previous plans called for splash blending and legacy conventional grades to be on hand. Jacksonville, Fla., is also slated for E10, but Colonial must wait for installation of tanks and logistics at the NuStar terminal, and a mid-summer rollout there is targeted.
Other companies don't cite the federal 7.76% target, announced by EPA on Feb. 8, but there is clearly a rush to make the conversion to E10 in other traditional conventional gasoline markets.
Murphy just told its Florida marketers that it will begin receiving its own supply of ethanol this month (until now, it has depended on ethanol from the Kinder Morgan terminal). Product will initially be available on a splash blended basis, but by late spring, it will be preblended at the rack.
Others continue to guard their ethanol plans like state secrets. However, an OPIS survey conducted last month yielded planned ethanol tankage rollouts in the following locations (estimated dates are provided for debut of ethanol blending):
Alabama: Murphy, Anniston (April/May); Marathon, Montgomery (summer).
Arkansas: Magellan, Little Rock (April)
Florida: Motiva, Ft. Lauderdale(spring); TransMontaigne, Ft. Lauderdale (spring/summer); Chevron, Jacksonville (3rd quarter); Chevron, Panama City (summer); Motiva, Tampa (spring/summer)
Georgia: TransMontaigne, Albany (spring/summer); Kinder Morgan, Athens (spring/summer); Motiva, Bainbridge (spring/summer); TransMontaigne, Bainbridge (spring/summer); Chevron, Doraville (spring/summer)
Maine: Citgo, So. Portland (spring/summer); Gulf, So. Portland (spring/summer)
Mississippi: TEPPCO, Aberdeen (spring/summer); TransMontaigne, Collins (spring/summer); Maples, Meridian (spring/summer)
North Carolina: BP, Charlotte (spring/summer); Center, Selma (spring/summer)
Pennsylvania: Petroleum Products Corp, Coraopolis (spring/summer); Gulf, Delmont (spring/summer); Buckeye, Emmaus (June); Gulf, Mechanicsburg (March); Petroleum Products, Mechanicsburg (spring/summer); Gulf, Pittsburgh (spring/summer)
South Carolina: Kinder Morgan, No. Augusta (spring/summer); Magellan, No. Augusta (spring/summer); BP, Spartanburg (April); Magellan, Spartanburg (spring/summer)
Tennessee: BP, Knoxville (spring/summer); Lion, Memphis (spring)
Virginia: BP, Montvale (spring/summer)
February 14, 2008
House Re-introduces Energy Tax Package, But Debate Delayed
The House Ways and Means Committee recently introduced a revamped version of the energy tax package, but consideration on the House floor this week -- as had been anticipated -- is being delayed to give members more time to review the proposal, a House Democratic leadership aide confirmed late Wednesday.
H.R. 5351, similar to the $16 billion energy tax package passed by the House in August 2007, would primarily roll back oil company tax breaks to help fund renewable energy projects. According to the five-page summary made available late Wednesday evening, the tax package would extend the $1/gal tax incentives for biodiesel and renewable diesel by two years, to Dec. 31, 2010; provide a new 50cts/gal tax credit for cellulosic ethanol through the end of 2010; and provide limits ensuring the tax credits would only be received for biofuel produced and used
in the U.S.
A similar version was included in the Senate's initial energy bill last year, but in order to receive ultimate passage and be signed into law, Senate Democrats had to strip out the energy tax package.
"If Congress fails to act this year, many of these valuable tax credits for renewable energy will expire," said Ways and Means Committee Chairman Charlie Rangel (D-N.Y.). "The Senate recently debated extension of expiring energy tax credits and this legislation gives them an opportunity to follow through on their expressed interest by working with the House to pass this bill," he added.
Initially, the legislation was to be debated on the House floor today, but then it was decided that would be delayed. "We are confident that this measure will be successful, but given this week's limited schedule, we wanted members to have more time to review the proposal," the House Democratic leadership aide said in an e-mail message.
The House is in recess next week for Presidents' Day, and the bill will be considered once the House returns, the aide told OPIS.
It's unclear whether the Senate would be receptive to another attempt at passing the energy tax package.
Meanwhile, as news circulated late yesterday that the House was getting ready to re-introduce the tax package, American Petroleum Institute (API) President and CEO Red Cavaney sent a letter to Congress, voicing his opposition to the move. "Just last December, Congress recognized the extremely harmful effects such taxes would have on future U.S. energy security when it wisely rejected such measures in enacting energy legislation. Nothing in the national energy picture has changed to warrant a reversal of Congress' earlier decision," said the letter.
The tax package repeals some tax breaks given to oil companies, which API views as a tax increase. "Promoting the use of alternative energy resources is a worthy energy policy goal. Doing so by imposing new taxes on the oil and natural gas industry would not help supply the stable and affordable supplies of energy necessary to meet the growing needs of American consumers," the letter added.
February 12, 2008
RINs Electronic Trading Exchange Gears Up
Renewable fuel credits will soon have a new place to trade - RINMARK. Open
to fuel industry stakeholders and speculators alike, the online exchange hopes
to monetize interest in the new market and pump up liquidity.
Launched on January 30, the Internet-based trading platform for Renewable
Identification Numbers (RINs) has so far attracted the interest of about 50
parties. About half of them, mostly net sellers such as gasoline blenders or
ethanol producers who can blend fuel, have completed or are working on their
registrations.
"We wanted to start slowly," said John Gelbard, managing director of RINMARK, explaining that the website would initially serve as a bulletin board for values as interested parties continue to sign up with RINMARK, the RINSTAR fuel registry and the Environmental Protection Agency. The next phase of electronic trading should get going in March, Gelbard said.
Fuel marketers might not be thrilled by another paper market, however. Several key associations have targeted futures' exchanges and derivatives markets where pricing benchmarks are often subject to Wall Street money flow. Hence, another exchange that welcomes and encourages participation by investment banks and hedge funds won't be cheered by jobbers and C-store chains.
RINs allow fuel suppliers hampered by inefficiencies in biofuel supply infrastructure to meet obligations indirectly and financially rather than physically. But a run-up in RIN values unrelated to physical biofuel supply could increase the financial pain of what's already a cash flow strained business, marketers warn.
RINMARK was launched by Renewable Trading Services, LLC, a venture formed by
Belzberg Technologies, which designed the exchange platform; biodiesel marketer
AgriFuels, LLC; derivatives brokerage I.A. Englander & Co., Inc. and the
Freedom Group, Inc.
RINs are the numeric codes generated by renewable fuel producers and
importers that are assigned to batches and transferred to buyers, either with
the physical biofuel or separated from it, as a credit. RINs have in essence
become the currency-for-compliance in the federal Renewable Fuel Standard
program and companies have been trading them directly and through brokers since
September 1.
RINMARK's Gelbard, who is also a senior vice president of I.A. Englander, sees RINs trading as more than a market-based program to transition fuel blenders, importers and marketers to greater use of biofuels.
Large corporations looking for a way to neutralize their carbon footprints
could buy RINs and retire them - much as they did with sulfur credits. Greater
competition for RINs could squeeze prices and attract trade from financial
players seeking
new markets.
Outsider participation in the RIN market could inject more biofuel into the U.S. fuel pool, according to Gelbard. "By allowing speculators in, the EPA wants an open marketplace for RINs and one which encourages biofuel production," he said.
Interest from hedge funds and investment banks brings with it the opportunity to create and trade purely financial RIN products.
An exchange traded fund (ETF) is possible, as is a "synthetic" RIN, akin to
American Depository Receipts (ADRs) in the U.S. market for foreign equities,
said Gelbard, whose experience includes trade in securities, security
derivatives and commodities (gold, sugar and coffee).
Renewable Trading Services stands ready to buy physical RINs and issue paper
RINs against them. Those interested in participating in the market but not
wanting to do the EPA paperwork required in the physical trade of RINs would
buy the paper RINs, which could be converted back to physical.
RIN Clearinghouse In Place; Financial Clearinghouse On the Way
The exchange will work with the RINSTAR renewable fuel registry, a product of Clean Fuels Clearinghouse, which got its start with sulfur credits in 2001. Clean Fuels is the trade name of Freedom Group, Inc., one of the four partners in RINMARK parent company Renewable Trading Services.
RINSTAR validates RIN ownership by sellers before title is transferred to buyers. Some companies trading directly with each other are using the registry to independently verify RIN ownership, a process that can be difficult, especially for those who don't want to deal directly with the EPA.
Clean Fuels Clearinghouse went live with RINSTAR on September 1 when RINs
trade began. The registry clears "regulatorily" rather than financially,
according to company president Clayton McMartin.
"How difficult would it be to counterfeit a 38-digit number?" he asks. RIN validation, along with EPA reporting and paperwork, are the values the registry brings to the marketplace, McMartin said. The EPA can validate RINs but no sooner than two months after quarterly reports are filed.
As of February 5, Clean Fuels has handled 74,397 individual transactions, accounting for validation of more than 900 million gallon-RINs, McMartin claims.
Transactions include purchases, sales and separation of RINs from physical
batches of biofuel. RIN codes become separated after marketers have bought and
incorporated into their production biofuel volumes that are above and beyond
their obligations. The separated RINs can then be sold as unassigned or Type 2
RINs.
About 60% of RINSTAR's transactions have been for assigned, or with-biofuel, RINs with unassigned accounting for the balance. RINMARK will trade only
unassigned RINs.
Until RINMARK lines up a clearinghouse for the financial end of transactions, buyers will guarantee payment for trades by depositing funds into Renewable Trading Services' escrow account with Chicago-based Harris Bank. "The exchange doesn't happen until the money is at Harris and RINSTAR has vetted the RINs," Gelbard said. "Then we make a simultaneous swap."
RINMARK charges both buyer and seller 5% of the notional value of the trade.
February 6, 2008
NREL Study Finds Massive Improvement in Biodiesel
Fuel Quality
Orlando -- In what has to be a sigh of relief for the U.S. biodiesel industry, new results released this afternoon by the National Renewable Energy Laboratory (NREL) reveal a huge improvement in on-spec fuel last year, as compared to results from a similar 2006 survey, it was announced at the National Biodiesel Board conference here.
Nearly 90% of the samples offered by 56 biodiesel producers and tested by NREL between April and October 2007 were on-spec for 10 properties, said NREL Engineer Teresa Alleman. Those properties were: water and sediment, phosphorus, free glycerin, total glycerin, acid value, sodium potassium, calcium magnesium, flash point, alcohol content and oxidation stability. Cloud point was also looked at, although there is no ASTM D6751 standard for the property.
Out of the properties, oxidation stability seemed to give the producers the most trouble, with approximately 8.5 million gallons (out of the 278 million gallons from the 56 producers) out of spec, Alleman revealed. Other problem properties included free glycerin, which saw approximately 2 million gallons out of spec and acid value, which also saw approximately 2 million gallons out of spec.
The sample size represented 70% of the B100 market in 2007, Alleman noted. Large biodiesel producers (although undefined) encompassed the majority of the survey, representing 89% of the 278 million gallons tested, followed by 10% for medium companies and 1% for small companies. The companies surveyed used a variety of feedstocks to produce the biofuel, she noted, and the remaining 51 biodiesel producers that did not participate in the survey most often cited a lack
of product.
If the survey just focuses on members of the NBB's voluntary BQ-9000 fuel quality program, the results are even better, Alleman explained. As of April 2007, there were 19 producer members, 17 of which participated in the NREL survey (representing 74% of the volume tested). "BQ-9000 companies passed all tests, with only one exception; One sample failed for water and sediment, likely due to contamination," she said.
While she did not compare the BQ-9000 test results versus the previous year's survey, the overall 2006 survey found that 59% of the 86 company B100 samples tested (representing 250 million gallons) were out of spec on one or more of the D6751 properties.
"These data show that the biodiesel industry has achieved dramatic improvements in fuel quality since 2006," said NBB Technical Director Steve Howell. "We expect that this trend will continue so that virtually all biodiesel sold in the U.S. meets these requirements in the very near future," he added.
"In the summer of 2006, our Board of Directors put into place a strong fuel quality policy with the goal of increasing the level of in-specification biodiesel in the U.S. to 100%," said NBB CEO Joe Jobe. "The NBB's outreach efforts with enforcement agencies and our investment in the BQ-9000 program have yielded terrific results, and we'll continue to push for 100%," he added.
NBB is no stranger to biodiesel quality spec concerns. In November 2006, it released results of a national fuel quality testing study, finding that 50% of biodiesel samples pulled between November 2005 and July 2006 were out of spec for incomplete processing. Previously, the biodiesel industry struggled with fuel quality issues in Minnesota, shortly after the state's 2% biodiesel mandate came into effect in 2005. The state was plagued by numerous complaints of clogged fuel filters and fuel that did not meet specifications. Initial testing indicated an overabundance of glycerin in some B100 base-stocks, and state officials halted the mandate three times, so the out of spec fuel could be drained and replaced.
Meanwhile, NREL's 2004 B100 survey (testing 25 million gallons from 22 producers) found that 85% of the samples met the ASTM D6751 properties, although four samples failed with high levels of phosphorus, total glycerin and acid numbers. NREL did not conduct a survey in 2005, although the immediate reason was unclear.
While the survey tested biodiesel produced from numerous feedstocks, Alleman told OPIS after her presentation that no specific feedstock could be singled out as having difficulty meeting ASTM specs versus another.
NREL's final technical report on these results should be published by mid-February, Alleman noted. Additionally, the agency hopes to conduct a 2008 survey, which would likely begin in FY2009, beginning in the last few months of this year.
February 1, 2008
Petrobras Ready to Ramp Up Role in U.S. Downstream Oil
Brazilian state oil firm Petrobras will buy out joint venture partner
Astra's interest in a Texas refinery in the next few months, but won't stop its
North American expansion there, sources say. The company may purchase other
U.S. refining assets, and is even toying with the possibility of a branded
gasoline effort.
Petrobras is close to wrapping up a deal for the 100,000 b/d Pasadena
refinery, which languished on the block for four years before Astra bought it
in early 2005. In February 2006, Petrobras ponied up $370-million for a 50%
interest. The Brazilian company will decide later this year whether to invest
more than $2-billion and double the plant's capacity to 200,000 b/d by 2011.
Regardless of size, it will configure the plant so that it can run mostly
Brazilian crude.
M&A contacts believe that the Petrobras buyout of Astra will be at a "big
number" that will value the refinery at well over $1-billion. The plant
struggled for many
years to break even or post a profit, but it has delivered
windfall returns in the
last three years.
The other refinery Petrobras is eying is Valero's 275,000 b/d Aruba plant.
Negotiations in recent months reached the point where the matter was put in
front of the Petrobras Board of Directors, but the company balked at some
conditions. Aruba's diet of mostly heavy crudes like Maya makes it a good fit
for Petrobras and Brazilian Marlim crude, analysts say. However, Aruba has long
had union problems and a less than stellar performance track record, so the
sophisticated and very disciplined Petrobras is not likely to overpay for the
asset.
Petrobras is widely recognized in international oil circles, but few in the
U.S. realize that the company has advanced to where it has more capital, more
reach, and more clout than most other multinationals. A survey by Washington-based Petroleum Finance Corp. earlier this year ranked the company sixth among
all international oil firms, ahead of BP, Chevron, and Total. It has a market
value approaching $250-billion and is by far Latin America's largest company.
In 2007 alone, its share price soared some 93%.
It would be hard to find an oil company that has had a better 21st century
run. Last November, it announced one of the largest crude oil finds in three
decades, with a discovery in the deepwater Tupi field in Brazil's Santos Basin,
estimated to hold some 8-billion bbls of oil equivalent (BOE). That crude,
expected to come to market in the next decade, could push Petrobras ahead of
Venezuela on the production ladder. Current oil output is around 2-million b/d.
Last September, Petrobras said that it would spend $112-billion on upstream
and downstream development, of which some $15-billion is earmarked for overseas
expansion. It bought a stake in a small Japanese refinery in November, and it
has a bid on ExxonMobil downstream "Esso" stations within Brazil, which amount to
a 7.2% market share.
The relationship with ExxonMobil has spawned talk that the company could be
a buyer for its U.S. refineries or stations. ExxonMobil has not sold a refinery
this decade, but it is known to have been reviewing downstream U.S. assets
since early in 2007.
Through N.Y. and Houston offices, Petrobras trades in U.S. crude and refined
products markets and also has a huge position in the nascent ethanol market.
New headquarters for U.S. operations in Houston are expected to employ some 360
people. Many years ago, the company was a large exporter of gasoline to the
U.S. East Coast but Petrobras fuel now stays in South America. It has designs
on much more rapid expansion for Gulf of Mexico crude, with a goal of producing
150,000 b/d in deepwater regions of the Gulf within five years.
While cashflow-rich, the company is quite deliberate in its expansion. The
Pasadena takeover has dragged along much longer than anticipated, and any plans
to roll out a retail effort are probably years away. In November 1999, for
example, Petrobras toyed with the idea of opening a chain of branded gas
stations in Florida with the "Fittipaldi" flag, named after the Brazilian
racing dynasty. The stations were never purchased or flagged.
January 25, 2008
Newly Active RIN Ethanol Credit Market Seen Robust
The new market for ethanol- and biodiesel-use credits known as Renewable Identification Numbers (RINs) has kicked into high gear as fuel marketers prepare their first reports on compliance with the federal mandate.
RINs are 38-character numeric codes generated by renewable fuel producers and importers that are assigned to batches and transferred to buyers, either with physical biofuel or separated from it, as a credit. They are the basic currency for compliance and trades in the Renewable Fuel Standard program.
Prices of ethanol credits recently soared to as much as 5cts gal from the 0.25cts gal seen in late 2007. Millions of RINs separated from their batches by marketers who have bought and blended the ethanol into gasoline above and beyond their volume obligations are being sold to those who need help meeting their quotas. There's no doubt that a looming deadline motivated enough serious buyers to create liquidity, but the near-doubling of the Renewable Fuel Standard in 2008 could keep trading volumes, if not prices, running strong.
The market has come a long way in a short time. The work of tracking and reporting RINs was a hassle to be avoided when the compliance program began in September.
"With no one willing to pay more than 10-20 points/gal (0.1-0.2cts gal) for RINs, there was little point in companies handling them," said one blender and retailer who, without gasoline production, is naturally long ethanol and in a position to sell RINs. "Low value, new regulatory obligations, more work for the back office - why bother?" he said, recalling players' initial response to the credits.
A modest RFS and ballooning ethanol production in 2007 meant that gasoline marketers' obligations last year weren't going to be difficult to meet. The market was long RINs and they were obtainable. "It was just a matter of (refiners and importers) finding them," the blender/retailer said.
But soon after New Year's Day, 2007 RINs rose to a penny, then 1.25cts gal and then up to 3.5-3.75cts gal. RINs for 2008 quickly became even more valuable.
"In the feeding frenzy, people recognized the 2008 requirement was dramatically higher than both 2007 and the old 2008 level," put into place by the Energy Act of 2005, a market participant said. In short order, Year 2008 RINs were changing hands for 4cts and 5cts gal.
Values are said to have moderated since last week's flurry. At presstime,
2007 RINs were being talked in a range of 1.5 cts to 2.25 cts, according to brokers. 2008 RINs were less active and notionally valued at about the same level as 2007 credits.
The market has attracted the interest of hedge funds and other speculators who go to the trouble of registering with the Environmental Protection Agency and follow the regulatory requirements such as filing quarterly reports on RINs held.
Even at current prices, "it's the cheapest call option" in the commodity market, said one market participant. "There's nearly unlimited upside."
RINs Front And Center For Market In 2008
The jump in values was an eye-opener for many, adding a new dimension of risk to ethanol-blending.
For gasoline importers RINs are an added cost of doing business. But RINs also introduce new price uncertainty for importers which could expose the U.S.
to greater supply risk depending on how they fare in the new market, in the opinion of one blender.
Other marketers with blending obligations are weighing the implications of 2008's much larger RFS - 9 billion gallons, up from 4.7 billion in 2007 and higher than the former 2008 mandate of 5.4 billion.
The EPA, which enforces ethanol-use regulations, obligated marketers to blend ethanol into 4.02% of the gasoline they sold in 2007. Based on the higher requirement of the new energy legislation, that obligation could jump to as much as 7.5% for 2008.
"That's a huge amount of conventional gasoline that will have to have ethanol blended into it," said one refining executive. The limited amount of cost-efficient transportation between ethanol's Midwest production base and the largest coastal fuel markets will continue to be a problem, he said.
On par with infrastructure bottlenecks as a RIN value driver is the fate of
2008 ethanol supply. Current output of 7.3 billion gal/year and an additional
3.2 billion gallons planned to come on line in 2008 should be sufficient to meet the use mandate but a rise in corn prices could again narrow profit margins and pull production capacity below 100%.
Gasoline marketers had some leeway on their ethanol obligations in 2007. If they don't meet the mark for 2007, they can carry over as much as 20% of their renewable volume obligation into 2008. However, going into deficit for two consecutive years puts obligated parties in violation and may subject them to penalties of up to $32,500 per violation per day.
EPA enforcement sources downplay the fine, saying the amount is the standard penalty, rarely imposed and with alternatives readily negotiated. But most gasoline marketers are apt to play the RINs market for all it's worth rather than risk EPA enforcement action.
"We're okay on 2007 (ethanol obligations) but we're in wait-and-see mode for 2008," said a refining executive. The company, a large gasoline supplier, is working the RINs market under the assumption that they will be held fully accountable for their part of the 9 billion-gallon 2008 mandate. "That's what's driving us now," he said.
Price of Admission - Ethanol Purchase and Blending Capacity
Anyone can trade unassigned credits, known as Type 2 RINs, but not everyone can generate them. The keys are ethanol ownership and use.
An oxygenate blender, for example, can separate RINs from batches and participate in trading but only if he actually blends renewable fuel that he owns into gasoline or diesel. Separated RINs become unassigned RINs that can be traded without fuel.
For more information about how the RINs work and who can trade them, consult the EPA's extensive FAQ available at http://www.epa.gov/otaq/renewablefuels/420f07041a.pdf.
January 24, 2008
New RFS in 2007 Energy Bill Seen Boosting Biofuel, Ag Prices, Study Says
The impact of higher ethanol and biodiesel mandates in the nations' fuel supply resulting from the new energy bill enacted last month will cause much higher agricultural feedstock prices as it also instigates more biofuel production and
use, a new congressional staff report prepared by University of Missouri economists concluded.
The report, "The Energy Independence and Security Act of 2007: Preliminary Evaluation of Selected Provisions," considers various scenarios and assumptions under the act's new renewable fuels standard -- basically stating that it boosts corn ethanol production nearly 24% and soy-based diesel output by 89.3% between years 2011-2016 over what it otherwise might have been. The assumption for such a scenario is that both biofuel tax credits and ethanol tariffs currently scheduled to expire are maintained, according to the university's Food and Agricultural Research Institute which compiled the report.
In absolute numbers, the report indicates ethanol production which would reach 11.71 billion gal by 2016 without the new law, will instead touch 14.5 billion gal. At the same time, biodiesel production that would otherwise run about 510 million gal will instead reach 960 million gal -- assuming tax credits and tariffs are extended.
"To generate this level of increased biofuel production, the average price paid to biofuel producers must be higher than it otherwise would have been," noted the report. Under the same assumptions, the new RFS standard results in a 17.4% increase in average wholesale corn-ethanol prices and nearly a 37% addition to average soy-biodiesel prices. However, corn prices gain 8% more than they would have without the new RFS and, over the same period, soybean oil prices surge an additional 36%.
Over the 2011-2016 period, new RFS-required demand gains for ethanol will boost corn use 1.1 billion bu annually. Some 30% of the increase will be fed by more corn output, another 30% from cuts in exports with the balance coming from less domestic use in other areas, such as less use as animal feed. The new RFS schedule will also up soy oil use in biodiesel by an average 2.69 billion pounds -- adding more than 91% from what it would have been without the legislation.
The impact on the corn harvest from additional biofuel demand generated in the RFS is expected to expand it by an additional 2 million acres/yr. But at the same time, soybean acres change very little -- essentially showing no additional gain in acreage due to the higher RFS.
"These estimated impacts...are contingent on a wide range of assumptions," conceded the authors. "Changing these assumptions sometimes dramatically changes the magnitude or even reverses the direction of results reported." For example, removing the assumption that current ethanol import tariffs and federal biofuel blending credits remain in place generally make the estimated impact of the 2007 energy legislation much more significant.
Ethanol production from corn, without the new RFS mandate and following expiration of tariff and credits, might come to only 8.11 billion gal by 2016. But the new RFS jacks that up by 73.5% -- to 14.07 billion gal --- still about 3% less than the new RFS/credits and tariff-maintained scenario described above. The impact on biodiesel is even greater, with soy-based production only about 230 million gal without the new RFS or credits, but jumping nearly 310%, to 960 million gal under the RFS even if the federal blender credit expires.
"To meet a billion gal biodiesel mandate without the dollar per gallon biodiesel tax credit, wholesale prices for biodiesel must almost double from those that would prevail without [the new energy bill mandate] or the tax credit," added the report. But at $4.19/gal, biodiesel prices under the assumption would be almost the same -- $4.20/gal -- as under the new RFS/credits extended assumption, but still about 37% more than if there were no RFS and while credits were maintained.
In addition, if crude oil prices hold above $80/bbl, the study authors indicated corn-based ethanol production could eventually exceed 15 billion gal/yr even without the new RFS mandate. This assumption suggests that if petroleum prices fell sharply from current values, there would be a greater chance that corn-based ethanol production would fall short of RFS levels if the new mandate were not in place.
Meantime, authors of the report noted that it should be considered preliminary analysis. It is a "snapshot" of the impact of selected provisions in the 2007 energy bill, which they will later expand to include further provisions such as that requiring cellulosic ethanol and other advanced biofuels.
January 22, 2008
Ethanol Imports Plunge, Brazil Shutout in November, Commerce Numbers Show
As many expected, and economics appeared to dictate, government officials reported U.S. ethanol imports in November plunged to the lowest level of the year -- with ethanol powerhouse Brazil completely shut out of the process.
Overall fuel-ethanol imports in November, according to data from the U.S. Department of Commerce's International Trade Commission, totaled a little more than 13.374 million gal -- down 64% compared to October imports. Brazil, the world's top ethanol exporter and usually the top source for U.S. ethanol imports, sent no ethanol to the U.S. in November after shipping nearly 6.23 million gal the previous month.
Ethanol shipments from Caribbean and Central American nations that made up nearly all the imported material in November were also slashed considerably for the month. A total of nearly 12.77 million gal arrived from the region, where producers eligible for the U.S. Caribbean Basin Initiative (CBI) can avoid the 54cts/gal secondary tariff on fuel ethanol imports. That still represented a 58% drop in CBI-based imports compared to the previous month.
Jamaica was the source for the most imports in November, sending more than 4.67 million gal to U.S. ports during the month, according to DOC. Nevertheless, it was also nearly 62% less than Jamaica shipped the previous month. Not far behind was Trinidad and Tobago, which sent more than 4.61 million gal of ethanol to U.S. destinations in November -- a big jump from less than 136,000 gal reported coming from the islands in October.
Still, another key source of imports, El Salvador, also cut back shipments considerably in November. Almost 3.48 million gal of ethanol came from El Salvador to the U.S. over the month, less than half October's level.
At the same time, the Commerce Department also reported no ethanol imports from Costa Rica in November, a nation that provided more than 9.2 million gal in October.
Brazil has seen its shipments to the U.S. wane since summer, when low U.S. domestic prices made Brazilian imports uneconomical. Brazilian officials, while complaining about U.S. and European import tariffs, report that they expect overall ethanol exports dropped around 10% to 11% for all of 2007 versus 2006, to a little more than a billion gal.
Prospects for Brazilian exports are for further declines in 2008, according to Brazil industry consultant Datagro, perhaps down to less than 900 million gal. There was even word that a major U.S. producer may reverse some of the flow, with a transaction to send substantial ethanol quantities from the U.S. to Brazil in a ratable deal beginning in this year's second quarter and extended through the summer. In 2000, top U.S. producer Archer Daniels Midland inked a deal to export some 20 million gal of ethanol to Brazil.
While U.S. trade officials, in accordance with CBI trade regulations, hiked the quota for tariff-free CBI ethanol imports in 2008 by almost 29%, to 452.5 million gal, other looming factors may eventually affect the availability of foreign ethanol for U.S. markets. For example, sometime in the second half of 2008, Jamaica is expected to begin implementing 10% ethanol blending for gasoline sold on the island, though planning is said to still be in preliminary stages.
In any case, CBI-eligible nations, including those approving the new Central American Free Trade Agreement-Dominican Republic, are still expected to expand ethanol production and export capacity to the U.S. this year.
U.S. officials acknowledged that their latest import data did not include new possible capacity from the U.S. Virgin Islands where a plant came online late last year. In addition, Jamaican oil company Petrojam has plans to boost ethanol production by 50% at its 40-million gal/yr Kingston plant, to around 60 million gal/yr in 2008, while several other delayed plant projects may be in the works on the island as well as in Trinidad.
January 17, 2008
Marathon Now Providing E10 Gasoline Blends for Florida Distributors
Marathon today commenced posting prices for E10 or "gasohol" blends of gasoline at terminals in Tampa and Pt. Everglades, Florida.
Distributors have been notified that they will be able to lift regular, midgrade, and premium blends of the E10 beginning today. There are some requirements to meet designed to safeguard against transport drivers mistakenly lifting gasohol instead of clear blends, and retailers are urged to take the necessary precautions to convert stations to the gasohol slate.
More companies are expected to follow. Reports say that majors such as Shell and ExxonMobil will soon follow with their own preblended product. Both have had terminals and supply ready, but have been waiting on state regulators to clarify some of the specifications.
OPIS is hearing of numerous other companies that should be soon adding preblended E10 or allowing splash blending of gasohol along the Colonial and Plantation Pipelines.
January 15, 2008
Majors Say State's Failure to Revamp Regs May Mean Higher-Priced Fuel
Florida marketers may see a sharp spike at the pump this spring, thanks to state fuel specs that majors say will force them to make a boutique gasoline for the Sunshine State if they want to sell ethanol blends.
Adding ethanol to gasoline raises volatility levels. Other states in the Southeast, including the Carolinas and Tennessee, are in the process of modifying their specs to accommodate the increasing use of ethanol. But so far, Florida has refused to follow the trend.
As a result, majors say they cannot guarantee that the fuel they sell in Florida will always comply with state specs if regulators do not grant a waiver or offer other relief from some of the volatility requirements.
The state has tinkered with its rules and on Dec. 21 proposed some new standards. However, majors say the changes are not enough to make them comfortable with allowing jobbers to blend ethanol into branded gasoline.
Absent additional action by the state, the only answer may be to introduce a Florida-specific gasoline that will cost more to produce, they say.
While the state and majors argue, branded jobbers are at a severe disadvantage in the marketplace. Independent refiners and chain marketers, including Hess, Murphy, RaceTrac and The Pantry, are selling ethanol fuel blends and earning a federal tax credit of 5.1cts/gal in the bargain.
Meanwhile, there may be some basis to claims by majors that the state is turning "a blind eye" to off-spec ethanol blends being sold by some independents -- the state acknowledged last week that it does not test fuel samples for compliance with all specs.
"All we want is for the state to enforce the regulations equally or grant a waiver so that everyone gets to play by the same rules," says a marketing exec with one major oil company.
Branded marketers are in full support of majors on the issue, says Jim Smith, exec with the Florida Petroleum Marketers Association.
"Unless and until we can be assured that our suppliers can offer us a product that's both affordable and in compliance, we're going to have difficulty expanding the use of ethanol in Florida," Smith says. "The bottom line is that it is the retailers who will have to bear the responsibility for any fuel that doesn't comply."
Florida Fuel Testing Procedures Called Into Question
Majors who have tested the ethanol fuel sold by some of the independent companies in Florida say that samples they took show that the fuel does not comply with some state specifications.
In particular, they cite a regulation that governs vapor-to-liquid ratios, known as the TV/L spec. Majors say they cannot consistently comply with that spec if they use their current gasoline formula for ethanol blending -- and they say they doubt that independent refiners and marketers can do any better.
"The state just cannot be testing for TV/L compliance, that's the only answer that makes sense," says the major oil exec, noting that refiners have been complaining about the test issue for at least six months.
According to Dr. Matthew Curran, Florida's Bureau of Petroleum Inspection, the state tests retail and wholesale fuel samples daily and has found no ethanol blends that violate regulations (OE 12/24/07).
Curran said previously that the results of fuel tests conducted by majors would have no impact on the state's position, since the samples would not have been processed in state labs. However, Curran acknowledges that the state does not test for compliance with every state requirement, including the TV/L spec, because it does not have the equipment to do so.
"There is a [TV/L] requirement out there, but we don't test for it," he said. "I don't think any state tests for every parameter," he told Oil Express.
Since there is now "a significant interest" in the TV/L requirement, the state will buy new equipment so that it can conduct the relevant tests, he says. Curran does not know how much the equipment will cost, but estimates the state will pay $15,000 to $25,000 per instrument.
Although the state has not tested for the TV/L spec, Curran believes the ethanol blends being sold in the state by independents do comply with the rules. The state can use other calculations to get an estimate, and so "get a feeling of where those [TV/L] numbers are residing."
According to some refiner sources, states don't run TV/L tests because they're not only hard to do but take a long time. By the time the results are back, the product involved has been sold. In addition, some question whether the state has the resources to enforce all its own regulations -- there are only 60 or so inspectors to cover the entire state, according to one jobber.
Curran says it's up to majors to decide if they want to produce a new gasoline for ethanol blending in Florida. "The companies that have been selling ethanol fuel have been doing so successfully with fungible gasoline without making any changes," he said.
"Florida's proposals are currently the most restrictive in the southern states," says Dave Mica, executive director of the Florida Petroleum Council.
At issue are two specific regulations.
One is the T-50 spec, which concerns the temperature at which fuel burns and is aimed at assuring that it is blended properly. The second is the TV/L spec, which refers to vapor-to-liquid ratios. Majors say their current fuel would have trouble meeting both specs, depending on the season of the year.
Majors say the easiest answer would be for the state to adopt a standard developed in 1995 by the National Institute of Standards and Technology (NIST), which was devised by the automotive, petroleum and ethanol industry and state- level regulators to handle discrepancies in ASTM testing results as a result of the addition of ethanol to fuel.
The NIST 130 standard provides that E10 blends will be deemed to comply with all testing standards if the base gasoline and base ethanol meet full specs. Midwestern states that have heavily marketed E10 blends for the past 10 years have adopted the NIST 130 rule, and something resembling it was used by Florida itself from the 1980's to the mid-1990's, sources say.
Refiners and marketers thought the state might agree to adopt the NIST 130 standard until one company -- Chevron -- refused to go along with the idea, according to documents obtained by Oil Express. Thirteen other states, including South Carolina, have moved to the NIST standard, or a slightly amended form of it.
The next best solution would be for the state to adopt the same specs under discussion in Tennessee and North Carolina. Both states have proposed to standardize the T-50 spec to a consistent year-round measurement, and to either waive or reduce the TV/L vapor-to-liquid ratios.
Jobbers have pleaded with the state to adopt the NIST 130 standard or take the same approach as adjoining states, such as nearby North Carolina and Tennessee, so far to no avail.
Marketers say that it does not make sense to have specs on the books that the state fails to enforce, yet won't agree to change -- especially when the cost of such behavior will ultimately be borne by consumers at the pump.
January 10, 2008
Biofuel Analysts Weigh In on 2008 Predictions
Ethanol was further catapulted into the media spotlight in 2007, blamed for driving up the price of corn and causing a "fuel vs. food" debate over whether the fuel competes with food resources. Reacting to the high feedstock costs, there were also industry consolidations and announcements of projects being halted, but by the end of the year, the ethanol industry was given a political shot in the arm by way of an expanded renewable fuels standard (RFS). But what will 2008 bring? In our first round of interviews, OPIS asked two biofuel analysts to weigh in on their predictions. Comments from several more analysts will be included in a follow-up interview.
OPIS: What do you predict will happen to ethanol prices this year in general?
Kevin Book, Friedman Billings Ramsey: The macro factors that ushered in the new year (economic slowdown and $100/bbl oil) suggest that transportation fuels prices in general are likely to soften. Geopolitical risk and currency effects that lifted global crude oil prices are unlikely to contribute as markedly to price inflation for biofuels that originate from dollar-denominated U.S.
feedstocks and manufactured by U.S. biorefineries.
Ian Horowitz, Soleil Securities: I expect to see about the same behavior in
2008 as we did in 2007. Spreads to RBOB will stay relatively narrow in 1Q08, but as we exit the quarter with an additional 1 billion gallons of capacity, we will quickly reach discretionary blend, sending spreads back to below 25cts.
OPIS: Last year, there was a lot of industry consolidation and/or halting of projects in the ethanol industry. Do you see that continuing throughout 2008 -- and will that consolidation carry over into the biodiesel industry?
Book: Yes. Biodiesel won a federal backstop for the first time since the
2005 energy bill, but as long as potential capacity continues to outstrip the mandated minimum industry size of 500 million gal/yr at the outset, biodiesel producers will have to compete on price, exposing higher-margin producers to shutdown or sale.
Horowitz: I think the era of overtime on the construction site [for ethanol] is over. We won't be racing to get gallons on the ground quite like we have in previous years (which will extend out completion dates). I think we will see some of the weaker hands halt projects, but the big guys will continue to build. As far as consolidation is concerned, I would have no idea who could be a buyer (other than a financial player). There is always potential for an all stock deal (VeraSun/U.S. BioEnergy), but I am unsure of seller's interest in all-equity deals.
OPIS: What affect will passage of the 36-billion gallon renewable fuels standard in the energy bill have on the ethanol market in 2008?
Book: Most of the updraft is probably behind us. The RFS allows blenders to use 20% of the previous year's surplus credits to satisfy current-year obligations. Unless the EPA alters this feature of the RFS in future rulemakings, this sets a theoretical lower bound for 2008 volumes at 9.0 - 20% = 7.2 Bg/Y. When final 2007 RIN volumes are tallied, we will know whether this presents a risk.
Horowitz: Relatively tight 1Q08 supply/demand structure, quickly moving into an overbuild situation with send half 2008 being overbuilt (on a monthly run- rate basis) of over 1 billion gallons. I think the RFS provided a momentary relief for ethanol producers from a perception standpoint. It will be interesting to see how the industry reacts.
OPIS: Will we see a sustained market for $100/bbl+ crude and if so, what kind of effect will that have on biofuels?
Book: We forecast $80/bbl average crude oil price next year; we think this will be negative for biofuels. A pullback in oil towards this target would produce this effect. We expect economic factors to contribute to a weaker first half of 2008.
Horowitz: We are concerned that we are treading very close to demand destruction with respect to energy prices. While we are still in winter gasoline markets, refiners are seeing prices (and crack spreads) more indicative of summer. Although transportation fuels make up a relatively small percentage of per capita spending, if the markets continue at this level into the summer and experience typical seasonality, we could be seeing significant demand destruction.
OPIS: Have oil company strategies regarding ethanol supply changed? Are oil companies still intent on locking in long-term supply arrangements, or because of the ethanol surplus, are they more inclined to play the open market?
Book: Contracts are getting shorter. One of the price "safety valves" that made the spot market more attractive was imports. It may get harder for blenders to source imports from Brazil at low cost. Brazilian ethanol will probably count as an "advanced biofuel" [under the RFS], as it comes from bagasse-fired sugar mills, bidding up scarce volumes. Second, the (54cts/gal ethanol import tariff - vs 51cts/gal excise credit) spread is poised to increase from $0.03/gal to $0.08 post-farm bill. Third, the "duty drawback"
loophole is poised to close [included in a tax package likely to be attached to the farm bill]. This could force buyers to look again at longer duration contracts once it happens.
Horowitz: Blenders remain very much in the driver's seat. I think they may want to do longer contracts, but at wide spreads to the spot market. That may be something the ethanol producers won't be able to handle, which will push trades to the spot market. Blenders (I am sure) remain confident that they will be able to physically meet the mandate(s) while achieving margin enhancement for the foreseeable future.
OPIS: Will "Big Oil" continue to invest more dollars directly into ethanol infrastructure, or have they pulled back?
Book: Integrated oil companies are likely to see new expenditures for blending and storage infrastructure to meet rising volumetric requirements, but only a small fraction of retail stations (about 10%) are owned by the "Big Oil"
names. That puts the attractiveness of the new $180,000/station 33% [E85] investment credit entirely in the hands of independent retailers.
Horowitz: It's in Big Oil's best interest to keep midstream tight (just tight enough) so that they can meet their mandated blend rate (+ some excess), but not built out enough so that assets sit idle.
OPIS: Fuel quality issues have always been paramount with ethanol. Have they been overcome? And have fuel quality issues for biodiesel been overcome?
Book: I have encountered fuel quality issues almost exclusively in the context of biodiesel, and it isn't clear that the industry as a whole has overcome the perception (or the reality) that biodiesel has unacceptably high levels of impurities.
Horowitz: I think nearly all of the ethanol now being produced is to spec.
Biodiesel still has quite a ways to go both domestically and globally in adhering to either ASTM or EN [European] standards.
OPIS: Given the financial and overall credit risk crisis, where is most of the money for investing in the alternative fuel infrastructure coming from?
Book: As per the investment in "Big Oil" question -- this will depend on the cash flows won by retailers who could see a weak demand year, many of whom are independent and without the working capital to necessarily undertake expensive downstream conversions.
Horowitz: At the production level, I think there is very little opportunity to attract new investment (as a whole). Most financial participants seem to be looking at the production side as built out or at least nearly built out. We continue to believe that midstream players will build out their handling assets as long as the increased handling of the product is enhancing profitability or providing an attractive return. Downstream investing seems to be relatively difficult to implement. With most of the assets being held in independent hands, it seems like a stretch to assume that higher-blend dispensing assets will be built out to any degree for some time.
OPIS: In your opinion, how is the driving public adapting to ethanol blends, especially E85?
Book: By our numbers, if the U.S. light duty vehicle fleet cycles at current rates and 25% of new cars are flexible fuel vehicles [FFVs], it will take until
2022 for FFVs to comprise the 50% of the fleet necessary for a smoothly functioning E85 market (and retailers will still need to sell it). This could accelerate if manufacturers up their proportions of FFVs to get fleet credit, or if cars cycle faster when consumer cash flows recover to pre-slowdown levels. But there is a cloud to this golden lining: mileage equivalency remains a fringe issue as long as E85 continues to represent a small fraction of motor fuel. When it is more widespread, E85 may have to price a significant discount to E10 to compensate end-users for lost energy.
Horowitz: A) There is no E85 to speak of outside of the corn belt. B) All of my cocktail conversations inevitably come to, "When am I going to be able to put E85 in my Suburban?" I think there really hasn't been a consumer demand for the fuel. As far as E10 blends are concerned, I think they're seamless. People don't really care what they put in their gas tanks at this point. They're just looking at the price.
OPIS: What hot button issue in the biofuels sector do you expect to follow this year?
Book: The 2007 RFS amendments [in the energy bill] initiated a low-carbon fuels standard (LCFS) based on a "lifecycle analysis" of greenhouse gas emissions, tying climate change inextricably to ethanol from here on out. But this is where things get muddy -- I would expect serious battles about lifecycle analyses, particularly as all prospective builds have to beat a 20% improvement on conventional gasoline, which, in many case, will rule out firing plants with coal.
Horowitz: Although the American farmer seems to have responded very well to the increased demand for corn arising from domestic ethanol growth, what concerns us this year is that we seem to be setting up for a "battle for acres," where corn is on defense against a growing acreage shift to soybeans. As we fine-tune our corn forecasts, it seems like without some acres remaining in corn (bought back for soybeans), we could be fairly tight in 2008 and significantly tight in 2009. All of this is on the assumption of growing yield trends and decent weather. If either of those variables suffer a downward impact, we could be seeing corn markets at levels where ethanol production becomes even less of an economic opportunity than we saw in the third quarter of 2007.
January 8, 2008
Kinder Morgan May Lead Southeastern Charge to E10
Disregard those suggestions that maintain ethanol won't get much of a foothold in southeastern conventional gasoline markets. The region's largest terminal operator - - Kinder Morgan Southeast Terminals LLC (KMSC) has told suppliers that it intends to have ethanol and splash blending capabilities at numerous terminals by mid-April.
The storage won't come cheap or without strings attached. KMST wants gasoline suppliers to commit to at least a three year lease on capacity and they'll have to "turn tanks" often or incur even higher costs. Prices quoted range from about 5cts gal for one turn each month, but it ratchets down to 3.5cts gal for more frequent turns. Interested suppliers need to commit to at least 1500 bbl of space to
be considered.
Some of the targets are pretty robust. KMST intends to provide about 60,000 bbl of ethanol storage in North Augusta, SC, for example and will have about 70,000 bbl of ethanol tankage at Selma, NC. In Virginia, Richmond and Chesapeake will see more than 40,000 bbl each of ethanol space if plans are followed, and Charlotte will have several locations, including pipeline and rail hubs that will have about 83,000 bbl of ethanol storage. Greensboro, NC is slated for 28,000 bbl of ethanol and Athens, GA will get 18,000 bbl, sources say.
Another round of expansion is planned at an unspecified date, and that list will include facilities in Albany and Doraville, Ga.; Birmingham, Ala.; Knoxville, Tenn.; Roanoke, Va. and Spartanburg, S.C.
There is no mention of any breakout storage for a conventional blendstock or suboctane grade, so it's assumed that there will be some "octane giveaway" for 87 or 89 blends of gas.
January 3, 2008
Petrobras Biodiesel Plans Expand to Meet Brazil's
Blending Mandate
Brazilian state oil company Petrobras recently announced that it has begun marketing biodiesel in Brazil, and that it intends to build 10 new biodiesel plants within the next four years. Both plans are related to Brazil's 2% biodiesel blending mandate, slated to take effect tomorrow.
To meet the requirements of the mandate, Petrobras and its Canoas, Rio Grande do Sul-based subsidiary, Alberto Pasqualini, have begun to market 100.38 million gallons of biodiesel to Brazilian diesel distributors, up from the 1.2 million gallons it has already been marketing since the beginning of 2007. Petrobras acquired the primarily soy-based biodiesel from Brazilian producers that have been certified as employing fair-trade practices by the Brazilian government, according to Sillas Oliva Filho, manager of commerce in the ethanol and oxygenate division of Petrobras. He said that the company plans to expand its biodiesel coverage to markets outside of Brazil in the near future.
Petrobras' 10 planned biodiesel plants plans will add to the three scheduled to begin production in March 2008. Each plant will cost US$39.3 million, and together, the 13 plants will produce 850 million liters (about 225.55 million gallons) of biodiesel per year, which alone would exceed that necessitated by the national blending mandate. A 2% blend of biodiesel in every liter of diesel sold in the country will require approximately 800 million liters, or 211 million gallons, of biodiesel each year.
December 27, 2007
NPRA Outlines 2008 Prioritiesw
The year 2007 ended on a bang for biofuel producers, with the passage of an energy bill and enactment of an expanded renewable fuels standard (RFS). But how do the nation's refiners feel about the provision, since they're the ones who will be blending more of the product? And what will 2008 and beyond bring?
For the first of our annual interviews with various industry associations, OPIS speaks to Charlie Drevna, president of the National Petrochemical & Refiners Association (NPRA), for his thoughts.
OPIS: What are your organization's legislative goals for the coming year? What do you see as NPRA's biggest accomplishment of 2007 and its biggest disappointment?
Drevna: We have significantly augmented our advocacy, membership services and other entities within the association, which has enabled us to greatly expand our outreach across the board. I think we were extremely successful in shining a bright light on many of the potential problems and unintended consequences associated with an expansion of the federal biofuels mandate, and on the pitfalls of allowing the federal government to influence the markets, which ultimately hurts the American consumer. A broad spectrum of interests -- food groups, economists, environmentalists, editorial writers -- came to the realization that an expansion of the biofuels mandate would fail both consumers and businesses. Unfortunately, however, the political momentum generated in both Congress and the administration overcame the independent research that's been conducted showing that a massive increase in the mandate would actually yield more negative consequences than good.
Despite what I'm sure were good intentions on the part of many, the bill passed by Congress and signed by the president does not focus on developing new domestic energy, but on inefficient and market-distorting mandates. So I suppose the biggest disappointment was that the energy bill focused to such a great extent on renewable mandates, but the good news is that we are hardly alone in our disappointment, and that we have a strong message as these issues continue to emerge and the bill's provisions are implemented.
Moving into next year, you'll see a pivot to climate change legislation, not that climate and energy bills are mutually exclusive. It's a very important subject involving a number of key issues that merit closer scrutiny and deliberation, including the impact on American jobs, the costs to consumers and exactly how much can be achieved environmentally with the least amount of damage to the economy. We see the approaches for dealing with greenhouse gas emissions currently emanating from Congress as "All cost, no benefit." When addressing climate change and finding new ways to reduce emissions, we ought to be looking for ways to maximize the benefit with the least amount of cost to the consumer.
OPIS: There was legislative movement this year for energy-related issues, whether in several iterations of the energy bill or in the farm bill. What concerns does NPRA still have with the policy?
Drevna: Increasing the renewable fuels mandate is simply not a solution to our nation's energy challenges. Diversification is, and that includes expanding domestic supplies of oil and natural gas, particularly if members of Congress want to see this country become less reliant on foreign sources of energy.
Scientists and agricultural experts have stated their skepticism as to whether or not we'll be able to produce enough corn to meet the ethanol requirement -- and even if we can, the question remains whether we should, given the environmental and economic concerns involved. In addition, we now have a mandate to use massive quantities of a product -- cellulosic ethanol -- that doesn't exist yet commercially, and if it doesn't become available according to the timetable Congress has now set, refiners will have to pay the U.S. Treasury a fee for not being able to use it.
We're also concerned that Congress still may try in 2008 to single out companies in our sector by excluding them from provisions contained within Section 199 of the 2004 Jobs Creation Act that are intended to spur domestic investment. [Drevna is referring to language included in the tax package of the energy bill, which was dropped in order to gain passage, that would have repealed certain tax incentives for certain oil and natural gas producers.] In essence, we'd no longer have a level playing field in relation to other industries here in the United States, and we would also be at a significant disadvantage globally when we have to compete with state-owned companies in unstable regions. Excluding our businesses, repealing that provision specifically for certain companies, accomplishes nothing positive, but instead puts American jobs and our nation's energy security at greater risk.
These are all things that we're concerned about from an industry perspective, but the unfortunate reality is that the costs brought about through these policies will ultimately be borne by the American consumer.
NPRA opposes biofuel mandates, not biofuels themselves. We're the largest consumers of ethanol in the country. In fact, we're using far more ethanol today than what was prescribed in the Energy Policy Act of 2005 for this specific time frame. I know our friends in the pro-ethanol lobby say differently, but that's an inaccurate assertion meant to direct attention away from the pressure they're facing from food producers and environmentalists who share our concerns regarding the mandate. What we would like to see, rather than a mandate for non-existent or non-sustainable technologies, is an on-ramp provision. Instead, now we have arbitrary timetables for fuels that aren't even available. On the whole, however, we simply don't believe it's the role of the federal government to choose winners or losers in the markets.
OPIS: Would NPRA have preferred passage of President Bush's Alternative Fuels Standard (AFS), which would have widened the definition over alternative fuels to include hydrogen and coal to liquids, as opposed to the RFS?
Drevna: We have the same concerns with the AFS concept as we do with the RFS. The AFS is at least a little more open to different technologies, but that doesn't lead us to support it. It's ultimately still the federal government choosing winners and losers, and we'd still have to pay the Treasury a fee for not meeting the mandate, even if the technology that would enable us to do so doesn't exist.
OPIS: Ethanol receives the lion's share of attention in the biofuels sector, but biodiesel is also a growing component. What are NPRA's thoughts on that fuel and what kind of challenges does it face from a refiner's perspective for more widespread distribution?
Drevna: It shares many of the same problems. It's not very efficient -- its energy content is lower than that of petroleum-based diesel. It requires land to grow crops, prompting again the land use and food-vs.-fuel debates. It's not very reliable in colder temperatures and doesn't flow well at times, thus creating transportation and storage issues. It also isn't compatible with many engines, thus you'd be looking at the need for a massive turnover in equipment.
Additionally, biodiesel may cause increased nitrogen oxide emissions compared to conventional diesel.
OPIS: What does NPRA think about the viability of renewable diesel and as a possible commercial refinery end product? Should the fuel receive the same tax incentives as conventional biodiesel producers?
Drevna: Many NPRA members are interested in renewable diesel. In addition to ethanol and conventional biodiesel, renewable diesel would provide refiners with another renewable fuel for compliance with the federal RFS. NPRA believes that all technologies and processes should be treated equally, regardless of where they are produced or blended. The most notable economic challenge to the development of a viable, stand-alone biofuels transportation industry is the seemingly constant push to an ever-increasing mandate of these fuels. So long as sound, open and free marketplace dynamics and discipline are ignored through imposition of artificial and inefficient mandates, distortion of basic economic realities will continue.
The goal of the biofuels industry should be economic parity, or better, with that of refined petroleum products. That situation will never be realized so long as the imposition of mandates overrides basic economic fundamentals.
Energy policy based on mandates is not a recipe for success. We believe the best possible future for the biofuels industry rests on allowing the market to operate freely, because open markets permit supply and demand to be balanced in an equitable fashion benefiting both producers and consumers.
OPIS: Where does NPRA weigh in on language in the scaled-down energy bill that would reduce the 51-cts/gal ethanol tax credit by 5 cts/gal once a certain ethanol production threshold is reached? Would NPRA support a further reduction at a later time?
Drevna: NPRA does not have a position on the appropriate tax credit value for ethanol. The corn ethanol industry has received significant government support. In examining the continued feasibility of the 51-cents-per-gallon ethanol subsidy, Congress should consider the maturity of the ethanol industry, ethanol's cost competitiveness with other additives and fuels and potential implications of changing the subsidy.
OPIS: Similarly, what are NPRA's feelings on the 54-cts/gal U.S. ethanol import tariff and whether it should be extended?
Drevna: NPRA supports the elimination of the tariff on imported ethanol.
NPRA testified to that effect before the Senate Commerce, Science and Transportation Committee in May 2006, stating that Congress should consider at least a temporary suspension of the 54-cents-per-gallon protective tariff.
Ethanol lobbyists argue that there isn't a reason to suspend the tariff because additional imports are unavailable. If so, no damage will be done to ethanol if a suspension is approved. We said then, and we'll continue to say, that imports will materialize if it's clear that the tariff is suspended. Ethanol enjoys a 51-cents-per-gallon federal subsidy, in addition to numerous state subsidies, the mandate that all or almost all of the ethanol produced in the United States be purchased by refiners regardless of its price, and a prohibitive tariff to block imports. Suspension of the tariff should at least be tried as a method for increasing required supply.
OPIS: Some have said that the oil industry is not friendly towards ethanol and is making it difficult for gasoline stations to provide E85. Can you address those concerns and whether they're valid?
Drevna: Again, we're not anti-ethanol, as some unfortunately seem to believe. What we are opposed to is the government choosing winners and losers in the marketplace by dictating how much ethanol should be used, when, where, and by whom.
Remember, E85 is not our product, and until our businesses receive some sort of indemnification, there's a risk for them to provide that product "under our canopies" so to speak. In 2007, I told Congressman Rick Boucher's subcommittee that as our companies are required to install pumps and potentially distribute E85, those companies should be indemnified from any claims related to product quality arising from a dealer's sale of unbranded E85 or other alternative fuels that are not the company's products. In other words, who should be held liable for lead in toys, Toys "R" Us or the toymaker?
OPIS: What is NPRA's take on the push for higher ethanol blends nationally and in California specifically?
Drevna: If successful, it means that American drivers will be filling up at the pump a lot more because the higher the blend of ethanol, the less efficient our tanks of gasoline will be. Again, you're also looking at a significant number of challenges in terms of distribution. As the General Accountability Office pointed out this past June, the infrastructure to transport and distribute such large quantities does not exist. Since ethanol can't be transported through existing fuel pipelines due to its corrosive nature, it'll mean the need for more rail capacity, more trucks on the road and expanded shipping on our waterways. You can't build a pipeline distribution system overnight, particularly when you consider how long it will take to apply for and receive the permits to even begin construction.
More importantly, consider the costs to consumers associated with these higher blends. AAA now posts a BTU-adjusted price for E85 accounting for its lower efficiency. I've seen that price reach more than a dollar per gallon beyond what the price of regular unleaded gasoline is. I'm not sure that most Americans are aware of that, or even if it has sunk in at the legislative level.
OPIS: With much of the attention in 2008 focused on the presidential and congressional races, what energy-related priorities will your organization be looking for from candidates?
Drevna: We have a responsibility to our petrochemical members to continue the push for increasing domestic natural gas supplies since it's an important feedstock for them. Now that the president has enacted the energy bill, we'll continue to highlight the problems associated with increasing the RFS mandate and potentially singling out our businesses for punitive taxes, and we will continue to convey the simple message that domestic refiners are ready to work with Congress, this administration and the next one to be an integral and reliable part of our nation's energy future.
December 20, 2007
Energy Bill Expanding RFS Signed Into Law
With the stroke of a pen this morning, President George W. Bush signed into
law the second energy bill of his term, containing the first increase to
national average fuel economy standards in more than 30 years and the second
increase to national biofuels requirements in three years.
"Today, we make a major step toward reducing our dependence on oil, fighting
global climate change, expanding the production of renewable fuels and giving
future generations of our country a nation that is stronger, cleaner and more
secure," Bush said at the bill signing, hosted at the Department of Energy's
headquarters.
The bill signing caps the nearly year-long congressional battle to enact a
new energy policy. The House passed the final version of the bill yesterday by
a 314-100 vote and in the spirit of the conservation language included in the
legislation, it was transported to the White House last night in a hybrid
Toyota Prius.
The 822-page energy bill, an amalgamation of previously passed House and
Senate energy legislation, contains a nationwide corporate average fuel economy
(CAFE) increase to 35 miles per gallon by 2020 -- 10 miles per gallon above
where the CAFE requirement is today -- and a 36 billion gal/yr renewable fuels
standard (RFS) by 2022, to be administered by the U.S. Environmental Protection
Agency.
The new RFS would begin in 2008, requiring 9 billion gallons of biofuels and
11.1 billion gallons the following year. The RFS contains three carve-outs:
requiring 21 billion gallons of the overall mandate to contain "advanced
biofuels" by 2022, with 16 billion gallons of that amount, under the same
timeframe, from cellulosic biofuel. For the third carve-out, up to 1 billion
gallons by 2012 is required to be from biomass-based diesel.
"Advanced biofuels" are defined as cellulosic ethanol, ethanol derived from
sugar or starch (other than corn starch), biogas, biomass-based diesel, butanol
or other alcohols and other fuel derived from cellulosic biomass. Additionally,
biomass-based diesel is defined as renewable fuel that is biodiesel, although
fuel derived from co-processing biomass with a petroleum feedstock would be
considered an advanced biofuel and not biomass-based diesel.
With much more aggressive biofuel targets, this expanded RFS is likely to
have more of an immediate impact than what was required under the original RFS,
contained in the 2005 energy bill. According to the Renewable Fuels Association
(RFA), the U.S. ethanol industry currently has the capacity to produce 7.4
billion gallons of the fuel, with another 6.05 billion gallons of ethanol under
construction. Meanwhile, there is currently no production of commercial-scale
cellulosic ethanol, although the "advanced biofuels" carve-out begins in 2009,
requiring 0.6 billion gallons of the fuel.
The original RFS did not contain carve-outs, but required increasing amounts
of biofuels that were achieved several years before their mandated time. For
example, in 2007, the RFS called for 4.7 billion gallons, nearly 3 billion
gallons below what the U.S. ethanol industry has the capacity to produce today.
Those easily achievable targets were what drove biofuel interests to push for a
second, more aggressive mandate.
Among other biofuel highlights of the bill:
--establishes a new grant program for retailers to install E85 dispensers.
The bill authorizes $200 million for FY2008-2014, for a maximum grant per
station of $180,000. E85 station mandates, which had been previously discussed,
were
not included.
--amends the Petroleum Marketing Practices Act to ensure that franchisees
are empowered to install or convert equipment to offer alternative fuels,
provided they have the liability associated with the decision. This is to
address previous concerns that oil majors were preventing alternative fuels,
specifically E85, from being sold under their canopy.
--requires several biofuel-related studies, including on the feasibility of
a dedicated ethanol pipeline and on the adequacy of rail transportation of
ethanol.
In order to gain Republican support for the bill, both the $21 billion tax
package that would have repealed some incentives to oil and natural gas
producers -- but also contained extensions of several biofuel-related tax
incentives -- and a renewable electricity mandate were removed before the
Senate approved the bill last week. However, congressional Democrats have vowed
to revisit the issues next year, likely during debate over legislation
addressing global warming.
A slew of biofuel trade organizations and companies -- such as RFA, the
American Coalition for Ethanol, Archer Daniels Midland and VeraSun -- issued
press releases shortly after this morning's bill signing, praising the passage
of the increased biofuels requirement. Petroleum trade associations, which had
previously voiced their strong opposition to the mandate, were noticeably
silent on the president's action.
December 18, 2007
Florida May Implement New Ethanol Blending Regulations Early Next Year
Florida is pushing ahead with its plan to adjust the language and specs for ethanol-blended gasoline, but the new regulations may not be in place until early next year, said an official from the state's Department of Agriculture on Monday.
Like other southeastern and southern RFG non-mandated states such as Georgia, North Carolina, South Carolina, Tennessee and Kentucky, Florida is moving quickly toward blending more ethanol into gasoline due to cheaper ethanol versus gasoline as reported by OPIS in summer.
Blenders could blend up to 10% of ethanol in gasoline and are looking at a potential ethanol consumption of about 900 million gal/year in Florida.
Higher utilization of ethanol for gasoline blending could give marketers a competitive price edge at the pumps.
"We will have the final proposal ready by Dec. 21, and a public notice will be issued for 21 days," he said.
A public hearing may be scheduled if necessary to sort out any issues that may arise from the public notice period. The proposal will then be sent to the procedural committee for approval, and finally, to the secretary of state for approval.
"There is no timetable or deadline for this rule change. We are just moving along," he said.
The adjustments to loosen the required specs are expected to encourage more blending in the sunshine state. Currently, Murphy Oil, RaceTrac and Hess are already selling ethanol-blended gasoline in Florida.
Hess will expand its E10 blends of gasoline throughout Florida in a decision that will require the refiner to purchase more than 8 million gal/mo of ethanol. Most majors in the state have yet to move to ethanol, much to the anger of their branded jobbers who say they will not be able to compete with the cheaper Hess blends.
The official said that Florida is proposing to extend the 1 PSI waivers of ethanol-blended gasoline to year round. In winter, changes also include ethanol- blended gasoline could contain 1%-10% of ethanol instead of 9%-10% in winter.
Florida will change the T50 specs requirement to 150 degrees Fahrenheit in winter, in line with the ASTM specs, and 158 degrees in summer.
December 13, 2007
Senate Farm Bill Amendment Calls for 36 Billion Gal RFS
With the scaled-down energy bill stalled in the Senate, U.S. Sen. Pete Domenici (R-N.M.) introduced an amendment to the 2007 Farm Bill yesterday that would include a 36 billion gal renewable fuels standard (RFS) package.
"...[I]t is clear that the energy bill has slowed down, largely because the House
has passed two major provisions -- a tax increase and a renewable portfolio standard -- that are untenable to many in the Senate," Domenici said Monday on
the Senate floor.
Additionally, even if the Senate did pass the scaled-down energy bill, "there would be nothing to prevent a conference from simply removing this...provision [the RFS]," Domenici said. "...[T]his amendment is relevant to the farm bill and necessary now to reinvigorate an ethanol industry that is looking to Congress to extend this mandate as soon as possible," he added.
The RFS proposed by Domenici is the same language from the RFS package included in the initial energy bill passed by the Senate in June (although slightly different than the RFS language included in the House scaled-down energy bill). Specifically, Domenici's amendment would cap corn-based ethanol at 15 billion gal and contain an "advanced biofuel" carve-out, mainly to be comprised of cellulosic ethanol, taking effect in 2016 with 3 billion gal and increasing by that amount to reach 21 billion gal (out of the 36 billion gal total) by 2022.
The RFS package also contains grants addressing renewable fuels infrastructure and calls for a handful of biofuel-related studies.
Whether the expanded RFS "is included in the energy bill or in this farm bill, it seems that ought to be the direction in which we move in this industry," added Sen. John Thune (D-S.D.)
After nearly a month-long stalemate on the farm bill, Senate leaders from both parties agreed last week to allow up to 20 amendments from each side to
be introduced.
In comments on the Senate floor this morning, Senate Majority Leader Harry Reid (D-Nev.) indicated he may get agreement to attach Domenici's amendment without a vote, along with other non-controversial amendments.
"I'm not certain that the energy bill is going to go anywhere now. There's broad support for the RFS in the Senate, so I think the reality is, we're going to confront it," said Senate Agriculture Committee Chairman Tom Harkin (D-Iowa), speaking to reporters on a conference call this morning, shortly after Reid's remarks. Domenici will offer the RFS amendment "and we'll just accept it...We're not going to be able to wait for the energy bill," he added.
Harkin expects the Senate to continue debate on the farm bill this week. "It's possible to finish [debate and vote on the bill] this week, but certainly no later than next week," he said. However, that timeline could be delayed if several higher priority bills are sent over from the House, such as an omnibus continuing resolution or Iraq war funding, he added.
The House passed its version of the five-year farm bill in July and since the current farm bill expired Sept. 30, the legislation has been extended under an omnibus continuing resolution.
While Harkin is hopeful the Senate will pass the farm bill this year, a conference to reconcile it with the House version of the bill is not likely until January, he said. "I don't think it will be a long conference...it's something that we could wrap up by the end of January," he added.
December 11, 2007
Deconstructing the Ethanol Blend Wall No Easy Task
Despite nearly $100/bbl crude oil, times are tough for ethanol producers.
Part of the problem is the nation's blending infrastructure is not keeping pace with the amount of ethanol being produced. That contributes to record-high inventories, keeps prices low and squeezes producer margins.
State-level regulatory hurdles and consumer mistrust also play their part in barring more ethanol from the U.S. motor gasoline pool. Several states are moving to adjust their fuel volatility specs to allow for more year-round blending of E10. However, key logistical hurdles remain despite pending regulatory relief.
Ethanol demand historically has hit barriers that suppress rapid growth, according to Logan Caldwell of Houston BioFuels Consultants who spoke at OPIS' recent National Supply Summit in Las Vegas.
Ethanol demand had a hard time breaking through the 4.4 billion gal/year level from January to May last year, Caldwell said. Then after ethanol replaced MTBE in June, demand was range-bound around 5.9 billion gal/year for the rest of the year. That increased to 6.2 billion gal/yr from this past February, and increased only slowly until this summer. Since July, demand has been increasing at a faster rate due to the strong blending economics that became apparent in late spring, and demand is now over 7 billion gal/yr, he said.
Meanwhile, ethanol production capacity will exceed 8 billion gal/year this year, and will grow to close to 12 billion gal/year next year and increase to13 billion gal/year or more in 2009, Caldwell said. Demand is growing at about 2 billion gal/year over the next year, while production capacity growth is accelerating to 3 billion gal/year, he said.
All of that supply looking for a market is likely to bump up against a lack of infrastructure capable of transporting, holding and handling the ethanol, Caldwell said.
Ethanol is mainly transported by rail. However, just 25% of product terminals have rail connections, Caldwell noted. "Many terminals removed rail facilities about 50 years ago as an unneeded maintenance expense occupying valuable real estate," Caldwell said.
Ohio, for example, has 52 gasoline terminals; 40 of which have pipeline delivery, 10 with rail and only eight with barge or ship access, he said.
Trucking ethanol is the most likely option to supply many terminals, Caldwell said. However, tanker-trucks are in high demand to carry a growing slate of products that cannot be commingled, such as gasoline and ultra-low- sulfur diesel.
More, terminals need dedicated tanks to store and blend ethanol. The same squeeze that's placing a premium on trucks impacts tankage as well.
Caldwell outlined the typical scope of work needed to modify a terminal to blend E10:
--Tank truck or rail car unloading including piping from the unloading area to the tank and an unloading pump.
--Tank modifications including better seals on a floating roof, replacement of aluminum roofs with carbon steel, a cover for the floating roof and coating of tank bottoms and walls.
--Loading facilities including stress relieving carbon steel piping for handling the ethanol, piping from the tank to the loading rack, a loading pump and a metering system for proportional loading of ethanol with gasoline.
--Safety, health and environmental measures including expansion of vapor recovery for the increase capacity, facilities for handling and disposing of ethanol/oily water drainage from tanks (a small tank to accumulate for later shipping off-site) and a foam system to fight ethanol fires.
Terminal upgrades for ethanol blending can cost anywhere from $500,000 to $2 million, Caldwell said, depending on its location, applicable regulations, owner standards and its current status. "There are instances of terminal modifications costing as much as $5 million," he added.
Also, completing a terminal modification can take anywhere from three months to two years to get the proper permitting and line up the engineering talent and equipment needed, he said.