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PM ACC 3/7/2016
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Industry Shift to Specialty Chemicals Moves Focus From Gulf Coast
Mar 7, 2016 | Houston Chronicle
By Jordan Blum
As profit margins tighten, the petrochemical sector is focusing more on producing specialty chemicals and materials, which aren’t always made on the Gulf Coast. -
Chemical Industry Seeks EPA Guidance on Pending Reporting Rule Deadline
Mar 7, 2016 | InsideEPA
By Maria Hegstad
Chemical industry representatives are raising concerns that EPA has yet to provide guidance on which manufactured, processed or imported chemicals companies must report to the agency under the 2016 chemical data reporting... -
Shale Gale Still a Force
Mar 7, 2016 | Chemical Week
By Robert Westervelt
Our cover feature this week assesses the state of North America’s shale-enabled cost advantage in an era of sharply lower crude prices as petrochemical makers prepare for two big US gatherings... -
Petrochemicals: The Genie is Out
Mar 7, 2016 | Chemical Week
By Clay Boswell
Cheap energy and feedstocks have attracted hundreds of chemical projects to North America, but most were planned when crude oil prices were two or three times higher than current values. Will they proceed? -
Clinton Makes Boldest Anti-Fracking Statements Yet in Flint
Mar 7, 2016 | E&E Daily
By Jennifer Yachnin
Democratic presidential primary front-runner Hillary Clinton last night vowed that if she is elected to the White House, she will aim to curb hydraulic fracturing in the United States, asserting that the practice is... -
States, Gas Industry: Feds Do Not Have Power to Regulate Fracking
Mar 7, 2016 | The Hill - E2 Wire
By Timothy Cama
The federal government overstepped its authority by issuing a rule to regulate hydraulic fracturing, according to several states and the gas industry. -
Week Ahead: Energy Bill, Flint Aid -- Take Two
Mar 7, 2016 | The Hill - E2 Wire
By Devin Henry
Senators are growing increasingly bullish on the prospects of returning to a major energy reform bill and a Flint, Mich., aid package. -
IPAA's Naatz Says Overlapping State, Federal Regulations Hurting Independent Producers
Mar 7, 2016 | E&E TV
As market uncertainty continues, how are independent producers adjusting to new financial and regulatory dynamics? During today's OnPoint, Dan Naatz, senior vice president of government relations and political affairs... -
A Call for College Students to Help Shape Their States’ Clean Power Plans
Mar 6, 2016 | New York Times
By Andrew C. Revkin
Back in January, Eban Goodstein, the director of the Bard College Center for Environmental Policy, distributed an invitation to college students and faculty across the United States to participate in “Power Dialog"... -
Indian Point: Past Its Expiration Date
Mar 7, 2016 | New York Times
By Paul Gallay and Michael Shank
Last month, samples showed a spike in the amount of radioactive tritium being discharged from Indian Point Energy Center into the groundwater near our homes along the Hudson River. -
Utility Regulators Practice 'Diabolical' Digital Hostage Crisis
Mar 7, 2016 | E&E Energywire
By Blake Sobczak and Peter Behr
A new class of kidnapper is polite and reliable and even provides online customer support. -
Refinery Fire Causes Temporary Closure of Houston Ship Channel
Mar 7, 2016 | E&E Energywire
By Nathanial Gronewold
An explosion at a Texas refinery linked to a Brazil oil industry scandal closed one of the busiest U.S. ports over the weekend, but the impact was brief. -
Potential Obama Picks are Seasoned Regulatory Referees
Mar 7, 2016 | E&E Greenwire
By Robin Bravender
Two more high-profile federal judges with experience deciding environmental cases are reportedly being vetted by the White House for the Supreme Court vacancy. -
Clean Coalition: How Utilities and Greens Teamed up to Pass Oregon's 50% RPS
Mar 7, 2016 | Utility Dive
By Herman K. Trabish
The story behind Oregon’s just-passed 50% renewables mandate contains lessons for states across the country.
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Industry Shift to Specialty Chemicals Moves Focus From Gulf Coast
Mar 7, 2016 | Houston Chronicle
By Jordan Blum
As profit margins tighten, the petrochemical sector is focusing more on producing specialty chemicals and materials, which aren’t always made on the Gulf Coast.
The petrochemical boom in the Houston region is built around the manufacture of base, or building-block, chemicals like ethylene that made using cheap, abundant domestic shale natural gas as feedstock. However, profits margins have shrunk during the oil bust and chemical companies are looking at other ways to make money, said Adrian Beale, IHS vice president of specialty chemicals.
Base chemical prices are tied to the costs of commodities like natural gas and oil prices, whereas specialty chemicals are linked to the performance of the products they are used in, Beale said, so there’s less volatility. Companies and shareholders desire more stability, he said.
Most chemical plants outside of the U.S. rely on a feedstock derived from oil, so Gulf Coast petrochemical plants had a huge price advantage when natural gas was cheap and oil sold for $100 a barrel as recently as 2014. Now that oil is $35 a barrel, much, but not all, of that U.S. advantage has gone away, Beale said.
“That’s what’s stimulated this huge wave of investment, especially along the Gulf Coast, was that huge advantage,” Beale said. Many of those new investments won’t come online for another couple of years.
He said he expects a trend of focusing on specialty chemicals to last for the next five years or so, which could cause a bit of a pause along the Gulf Coast after the current wave of new projects is completed.
“Even if oil prices go back up, we’re not expecting them to go back to the heights where they were before,” he said. “Even though the U.S. will have a kind of advantage, it won’t be as significant.”
Some of the biggest specialty chemical growth areas are in pharmaceutical ingredients, specialty polymers, electronic chemicals, cosmetics, fragrances and construction chemicals.
Oilfield chemicals was a big growth area of late, Beale said, but that demand has declined during the oil crash.
Much of the new specialty chemical growth will come in developing areas where demand is growing like China, India and the Middle East, he said.
Still, there is some specialty chemical growth in the Houston area.
Paris-based Total on Monday will inaugurate its new, $100 million high-purity, specialty fluids facility at its Bayport complex. Total’s Bayport hydro de-aromatization, or HDA, plant will produce a range of 40 different specialty fluids for customer use pharmaceuticals, crop protection, water treatment, printing inks, paints and coatings and cosmetics.
The “de-aromatizing” is done in part to reduce toxicity and air pollution concerns of the products, Beale said.
And the base chemical growth isn’t quite done yet. Total will decide later this year whether to build a $2 billion steam cracker in Port Arthur to produce ethylene, which is the primary building block of most plastics.
With China representing a big growth area for specialty chemicals and China having a lack of technological know-how on the topic, Beale said, China is looking to acquire Western companies.
The China National Chemical Corp., called ChemChina, is in the process of buying Switzerland-based Syngenta chemicals and agribusiness giant in a $43 billion deal. Syngenta has a crop protection biosciences plant in eastern Houston near Greens Bayou.
Such Chinese growth through European and American companies could trigger more political debate, Beale said.
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Chemical Industry Seeks EPA Guidance on Pending Reporting Rule Deadline
Mar 7, 2016 | InsideEPA
By Maria Hegstad
Chemical industry representatives are raising concerns that EPA has yet to provide guidance on which manufactured, processed or imported chemicals companies must report to the agency under the 2016 chemical data reporting (CDR) rule, as they say the agency has done with other list-based rules.
The CDR, in place since 2012, is EPA's main source of exposure information for most industrial chemicals. Before that, the agency gathered such information under a similar rule known as the Inventory Update Rule.
The CDR rule requires companies to submit information to EPA every four years on the amounts of chemicals greater than 25,000 pounds that they manufactured, imported or processed in certain categories. Submitters are also asked to provide any information they may have on how the chemicals are used. For the first time in 2016, the rule also requires companies to submit this information for production, processing or importation of more than 2,500 pounds annually of certain other chemicals that may face regulatory action.
The rule is authorized by section 8a of the Toxic Substances Control Act (TSCA), and provides much of the exposure information EPA has for TSCA-controlled chemicals.
Industry sources say they are most concerned about the second category of chemicals -- those subject to TSCA actions. The 2016 rule for the first time lowered the reporting threshold to 2,500 pounds for chemicals that are "the subject of any of the following TSCA actions . . . a rule proposed or promulgated under TSCA section 5(a)(2), 5(b)(4) or 6 . . . an order issued under TSCA section 5(e) or 5(f) [or] [r]elief that has been granted under a civil action under TSCA section 5 or 7," according to a January fact sheet that the agency released to assist companies.
"If only makes sense for EPA to come up with a unified list for those chemicals that have different CDR reporting requirements," an industry source tells Inside EPA. "It will be particularly critical for smaller businesses that lack in-house regulatory staff to manage these important reporting obligations."
Industry groups are asking the agency to provide a list of the regulated chemicals that must be reported if the companies cross this lower, 2,500 pound threshold. TSCA section 5 generally relates to new chemicals review and Significant New Use Rules (SNURs), one of EPA's few options for addressing chemicals that were on the market before TSCA was enacted in 1976. SNURs can also be used to control new chemicals as they come on the market.
TSCA section 6 gives the agency the authority to ban a chemical, though EPA has not successfully prosecuted a section 6 rule since its effort to ban asbestos was overturned by the U.S. Court of Appeals for the 5th Circuit in 1991. TSCA Section 7 allows EPA to seek a judge's order to seize a chemical the agency deems "imminently hazardous."
"The practical issue is that knowing the list of chemicals subject to the lower thresholds and the list of chemicals ineligible for certain exemptions is not straightforward," says Derek Swick, manager of regulatory and scientific affairs at the American Petroleum Institute, in a Feb. 18 email.
CDR Reporting
"Companies preparing for CDR reporting think it is essential that EPA provide the regulated community with a simple list of the chemicals that are subject to the lower reporting threshold, and of the chemicals that are not eligible for exemptions," Swick adds. "It is highly unusual (if not unprecedented) for EPA to implement a requirement that is chemical list-based, but for which EPA does not provide the chemical list. If it is not easy for EPA to generate the list, then it not reasonable to expect the regulated community to be readily able to do it."
The 2016 rule requires companies to begin reporting between June 1 and Sept. 30 on all chemicals that met the reporting thresholds in any of the years 2012-2015. Swick notes that companies are preparing to submit this information to the agency "and they need to have clarity on what chemicals are subject to the lower reporting threshold and ineligible for exemptions (i.e., the chemical name and [Chemical Abstracts Service] number). In past years, EPA had provided the list of these chemicals in the CDR instructions, but has not yet done so this year and may not be planning to do so."
Swick notes that EPA has hosted a pair of webinars for companies' staff to try to address questions and concerns about the reporting period, but has not responded to requests to produce a list of chemicals to which the lower reporting threshold applies.
Instead, Swick says the agency referred companies to its database SRS, "but it has also said that the database is not up-to-date regarding these TSCA actions. A company would need to check its chemicals one by one in this database system and even then would not be entirely confident of the results. This also creates a situation in which it is effectively necessary to identify all chemicals manufactured or imported above the lower threshold, in order to identify which chemicals to enter into the database to determine if the lower threshold does indeed apply."
An EPA spokeswoman did not respond to a request for comment on the situation.
Swick says that an additional complication is that EPA has finalized TSCA rules between 2012 and 2015, so it is also important to know the date by which EPA considers a rule to have been in effect for purposes of reporting the lower threshold chemicals.
EPA's January fact sheet says the rules' effects "on CDR reporting are assessed based on the status of the chemical substance as of the beginning of the submission period, when the reporting obligation becomes current . . . Thus, for the 2016 CDR, consider the status of a chemical substance as of June 1, 2016."
Swick says the selection of the beginning of the reporting period as the relevant deadline is also challenging for companies. "Companies will need to do the data collection and analysis well in advance of the beginning of reporting on June 1, 2016, when actual submissions begin," he says. "Allowing companies to consider the status of a chemical substance as of December 31, 2015 would be much more reasonable, as most companies are already doing the work to determine which chemicals they will need to report. This would also make it easier for EPA to publish a straightforward list of the chemicals that are subject to lower thresholds and ineligible for exemptions."
"A list of chemicals subject to reporting would be helpful," said Dan Newton, senior manager of government relations at the Society of Chemical Manufacturers & Affiliates (SOCMA), in a Feb. 25 interview. "Obviously, the TSCA inventory is a list. But for lower volume chemicals, a list would be helpful."
Newton added that the 2016 reporting rule could include "some small businesses that might not necessarily normally report," in part because EPA is expanding chemicals it wants information about, as well as the information it is seeking.
Newton's organization, SOCMA, represents batch and specialty chemical producers, processors and importers, many of them small businesses.
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Mar 7, 2016 | Chemical Week
By Robert Westervelt
Our cover feature this week assesses the state of North America’s shale-enabled cost advantage in an era of sharply lower crude prices as petrochemical makers prepare for two big US gatherings: AFPM’s International Petrochemical Conference at Dallas on 20–22 March and the IHS Chemical’s World Petrochemical Conference at Houston on 15–18 March (p. 21).
US olefin and derivative producers continue to benefit from low-cost ethane in North America but to a lesser extent than in the prior three years. Oil remains weak, closing at $34.69 on 3 March. North America’s shale advantage relative to naphtha has narrowed accordingly. Between June 2014 and January 2016, the Btu value spread between Brent oil and US natural gas fell from $13.61/MMBtu to just $3.04/MMBtu, a decline of 77%. Strong polyethylene demand and volumes have helped maintain derivative margins and mitigate weakness upstream.
While the advantage remains in place, concerns over lower oil may actually help by slowing the US build in capacity, which will tighten supply and boost margins longer term. IHS estimates nearly 12 million m.t. in firm capacity plans that will be added by 2020 (table). That’s a lot but not quite the deluge once feared. Some 20 cracker projects in the United States have been proposed, but only 4—Chevron Phillips Chemical, Dow Chemical, ExxonMobil, and OxyChem/Mexichem—are in advanced construction and expected to be completed by year-end 2017. A couple other cracker projects, Formosa and Sasol, have advanced to the infrastructure work phase but are not likely onstream before 2018. Several debottlenecks are also under way.
North America integrated ethylene margins are lower, but still profitable and advantaged. And North American margins should rebound despite significant new capacity as oil prices improve and the need for more ethylene, including higher-cost naphtha projects, pushes prices upward.
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Petrochemicals: The Genie is Out
Mar 7, 2016 | Chemical Week
By Clay Boswell
Cheap energy and feedstocks have attracted hundreds of chemical projects to North America, but most were planned when crude oil prices were two or three times higher than current values. Will they proceed?
With crude oil prices mired at $40–60/bbl for over a year, North America’s petrochemical industry has lost some of its advantage, and plans hatched when crude was over $100/bbl are looking less certain. Shale continues to grant US producer wishes for some of the lowest feedstock costs in the world, however, and over the long term, growing demand and recovering margins will drive a resurgence of capital investment. Projects already under way continue toward start-up, and the stream of announced projects continues to flow, if more slowly.
“North America has had strong investment in petrochemical markets, and we expect that to continue due to the shale advantage,” says Jim Brittain, president/energy and chemicals, Americas at engineering and construction firm Fluor.
The price of Brent crude oil regularly exceeded $100/bbl for much of 2014 but collapsed late that year and averaged barely $50/bbl in 2015, dropping to just $43/bbl in the fourth quarter. The price remains weak, averaging $31/bbl in January 2016.
North America’s shale advantage has narrowed accordingly. Between June 2014 and January 2016, the Btu value spread between Brent oil and US natural gas fell from $13.61/MMBtu to just $3.04/MMBtu, a decline of 77%.
A flatter cost curve
With almost 95% of the ethylene produced in North America derived from natural gas liquids (NGLs), the narrow spread has had a tremendous impact on regional competitiveness.
“The cost curve is very flat now for 90%-plus of the ethylene volume,” says Steve Lewandowski, senior director/olefins at IHS Chemical. During 2012–14, the naphtha cash cost was $1,000/m.t. higher than current levels, he notes. “Now it is $200/ton or less depending on butadiene and benzene recovery.”
The difference showed in 2015 financial results. US producers uniformly reported lower ethylene margins last year. LyondellBasell Industries’ ethylene margins in the country declined 17 cts/lb from 2014. They dived steeply in the fourth quarter, with the company reporting a sequential decline of 6 cts/lb.
A heavy turnaround season should improve ethylene margins during the first half of 2016, but producers expect to lose the gains in the second half. Further decline is unlikely, Lewandowski says. “But a further drop in crude at constant ethane price would say yes,” he adds.
In Europe, where 70% of ethylene is produced from naphtha, margins have been strong, rising to nearly €800/m.t. ($877.09) at midyear, but the price of crude oil is only one of the factors in play. “The improvement in European margins has been partially a result of declining oil prices and, therefore, costs but more significantly a result of a tight market balance,” says Matthew Thoelke, senior director/olefins and derivatives, Europe, Mideast, and Africa at IHS Chemical. “As cost declined in 2014 and 2015, tightness in the market allowed European producers to hold on to much of the cost saving in increased margin. This was supported by a tighter Asian and, ultimately, global market.”
Derivative consumers have not had the leverage to pull any of that margin back, Thoelke says. Domestic markets have been balanced to tight, while logistical costs, availability, and competition with Asian buyers have limited recourse to imports. Until global supply loosens, he adds, European ethylene margins will remain strong. “With a slight cost advantage versus Asia and a strong preference by European buyers to source European polymer, sellers in Europe have a relatively strong position,” he says. The situation is likely to change next year, however. “Increased supplies in Asia and the United States in 2017–19 are likely to put some downward pressure on global markets and force European margins down,” Thoelke says.
Project developments
Plans to build ethane crackers have provided a kind of index to North America’s shale advantage since Chevron Phillips Chemical (CPChem) announced its US Gulf Coast Petrochemicals project in 2011. To date, 20 US cracker projects have been proposed, and 4 are expected to be completed by year-end 2017.
Methanol capacity has followed a similar trajectory. US producers have brought online over 4 million m.t./year of production capacity during the last five years, bringing the regional total to 5.7 million m.t./year. IHS expects four more projects—Natgasoline, Big Lake Fuels, South Louisiana Methanol, and Yuhuang Chemical—to begin production during the next four years.
In total, at least 246 chemical capital projects valued at $153 billion have been announced in the United States since shale-advantaged natural gas and NGLs surged onto the market, according to data compiled by ACC. Most of these projects were planned when crude oil prices were at least twice as high and the shale advantage was overwhelming. When crude prices collapsed, companies began to reevaluate their plans.
The four crackers due by year-end 2017 will be completed, but others may be postponed or canceled, says Dow Chemical COO James Fitterling. “Half of what’s announced is in play, and half of that might come on in the timeframe that was committed to,” he said during the company’s fourth-quarter 2015 earnings call. “When the second wave comes is anybody’s guess at this point. Some people are saying 2018. I think it might even slide into 2019 or 2020,” he said, pointing to current financial conditions and the availability of construction labor. “I don’t expect a tidal wave of new capacity coming on,” he concludes.
In all, 10 crackers are likely to be built over the next few years, IHS says (chart, p. 22). Other projects are less certain.
Propylene reevaluated
North America’s on-purpose propylene projects, aimed at replacing supply lost when steam crackers shifted to light feedslates, are also getting a second look. Although regional crackers will not be switching back to naphtha feed and refinery supply may actually decline, improvements in the cost of producing propylene abroad from naphtha could outweigh the advantage of producing it locally by alternative technologies, at least in the medium term.
Flint Hills Resources has a 600,000-mt./year propane dehydrogenation (PDH) unit at Houston that has been operating since 2010. Dow started up a 750,000-mt./year PDH unit in Freeport, TX, late last year. Enterprise expects to begin operating its 750,000-mt/year PDH plant at Mont Belvieu, TX, in the first quarter of 2017. Formosa Plastics is building a 660,000-m.t./year PDH unit for its Point Comfort, TX, site. The company had originally planned to have the plant online in 2017, but IHS now expects start-up in 2019.
Other projects are still being evaluated, including BASF’s 475,000-m.t./year methanol-to-propylene project at Freeport. Meant to fill BASF’s US propylene deficit, the plant would go online in late 2019 if approved, but that is now in doubt. In February, BASF chairman Kurt Bock said the company expects to make a final investment decision during the second quarter. However, he also notes that the project would not be attractive with crude oil at $40/bbl.
Ascend Performance Materials is still considering building a two-train PDH unit at its Chocolate Bayou, TX, facility. A final investment decision is expected during the first half of 2016, with start-up planned for mid-2019.
Last October, Williams said that plans for a 525,000-m.t./year PDH facility to be built near Edmonton, AB, have advanced to the detailed engineering phase and that a final investment decision would be made during the first half of 2016. The company has also announced an agreement with North American Polypropylene, an affiliate of Goradia Capital, which would build an adjacent polypropylene plant.
A recent development in the news could complicate the plan, however. According to a 23 February report by the Wall Street Journal, Williams intends to sell its Canadian assets. The assets include an oil sands olefinic off-gas extraction plant at Fort McMurray, AB; a pipeline that carries the extracted NGLs to Edmonton, AB; and a fractionation facility for separating the NGLs. The proposed PDH plant would also be part of the Canadian operations. Williams has not confirmed the account, but the Wall Street Journal notes that the sale would go a long way toward meeting the company’s goal of selling $1 billion in assets this year.
Importing the advantage
Low crude prices have not been uniformly good news for European and Chinese olefin producers. Those planning to import the shale advantage in the form of NGLs or methanol will have to wait for their investments to pay off.
Ineos has made the greatest commitment to NGL imports, spending $700 million to build an ethane import terminal at its Grangemouth, UK, facility and another $500 million or so to build eight vessels to carry the feedstock. Ineos will supply the imported ethane to its steam crackers at Grangemouth and Rafnes, Norway, and ExxonMobil has contracted to take ethane for its steam cracker at Mossmorran, UK.
“At current oil prices, the economics for importing ethane are looking very challenged,” Thoelke says. “For some, the economics are still manageable, but they will certainly not achieve an acceptable return. Others may well lose money on moving product, but they may have no real option due to contractual commitments.”
Midstream companies are investing enormously to support the waterborne transport of NGLs. Sunoco Logistics has been building the Mariner East pipeline to carry NGLs from the Marcellus and Utica shale basins to the company’s marine terminal at Marcus Hook, PA. Ineos is the anchor customer. The pipeline currently has the capacity to carry 70,000 bbl/day, but the Mariner East 2 project will expand that to 345,000 bbl/day. Sunoco Logistics had planned to bring the new capacity online in late 2016, but resistance in communities along the pipeline’s path has delayed permitting, and the company now expects the expansion to be in service in the first half of 2017.
Despite the currently unfavorable situation, NGL imports remain an attractive option, even drawing interest from China. In February, Technip announced that SP Olefins, a subsidiary of Chinese producer SP Chemicals, plans to build a 650,000-mt/year steam cracker in Taixing, Jiangsu Province, China. The cracker will employ Technip technology and consume a feedslate of ethane and propane from North America.
Methanol under the microscope
More common, however, are plans to import methanol as feedstock for China’s many methanol-to-olefin (MTO) plants. By the end of 2016, 11 MTO plants with a combined olefins capacity of 6.7 million m.t./year will be online. Much of the new methanol capacity in North America is being planned in the expectation of supplying the plants, all of which are in China. MTO already accounts for 10% of global methanol demand, and it will be the fastest-growing application through 2025, growing an average of almost 10% annually, according to estimates by IHS Chemical.
Many of the methanol plants in North America expect these plants to be key customers. However, China’s MTO plants have some of the highest production costs in the world. “The economics of the new olefins-related applications are worse than envisioned originally, leading to low operating rates and delaying the recovery in the methanol market,” says Ben Nelson, v.p. and senior analyst at Moody’s. Low crude prices are meanwhile straining the finances of methanol producers, a recent Moody’s report says. The report notes that US methanol prices have fallen from about $1.90/gal one year ago to 65–75 cts/gal in February and March, propelled by the wave of new US capacity and falling oil prices. Over one third of global methanol demand goes into energy applications such as dimethyl ether and direct gasoline blending.
One of the most ambitious of North America’s methanol projects—Northwest Innovation Works’ plan to build 14.4 million m.t./year of methanol capacity across three sites in the Pacific Northwest—has been scaled back. In February, the company put plans to build a plant in Tacoma, WA, on hold, citing public resistance. “NWIW’s goal is to build a local industry that contributes to the economy and protects the environment by reducing global greenhouse gas emissions,” the company says. “Given these objectives, we have been surprised by the tone and substance of the vocal opposition that has emerged in Tacoma.” NWIW will continue to develop plans for plants at the Port of Kalama, WA; and the Port of St. Helens, OR.
No turning back for shale
The long-term trend still favors locating capital projects in the United States. Only the timing is in question.
Dow chairman and CEO Andrew Liveris said in an interview in January that he remains convinced the United States will maintain a leading feedstock cost position thanks to shale. “The only parts of the world where it is cheaper is in controlled markets, like the Middle East,” Liveris says. “The Saudis and others are beginning to unregulate their hydrocarbon markets. And it’s not just there. From Indonesia to China to Venezuela and the Brazil, people are moving away from regulated hydrocarbons and fuels to market-based [prices]. As that happens, I’m convinced the United States will be unequivocally the cheapest place in the world for natural gas and natural gas feedstocks.”
For now, however, lower oil and other commodity prices are impacting customers’ cash flows and abilities to fund projects at the same pace as recent years, Fluor’s Brittain says. “Some decision dates are also moving to the right as our clients work to make sure that they have the most capital-efficient solution to make a project viable in this market,” he says. “However, we are seeing steady spending on projects that make economic sense for our clients. They are looking at their slate of projects and continuing to fund priority projects that support their long-term strategy, albeit at a slower pace.”
Fluor is conducting front-end engineering and development (FEED) for a propylene oxide/tertiary butyl alcohol plant that LyondellBasell has proposed for Pasadena, TX; and for the ethane cracker and derivatives project that PTT Global Chemicals (Bangkok) has proposed for Dilles Bottom, OH. Other clients continue to discuss the development of petrochemical projects on the US Gulf Coast, Brittain says. The company is meanwhile building the Dow, CPChem, and Sasol ethane crackers that will begin production in 2017–18.
“Our clients are putting their projects close to the feedstock sources,” Brittain says. “North America, especially the US Gulf Coast, is well positioned for these projects due to the availability of shale gas and the large pipeline infrastructure.”
Possible futures
Several months after oil prices began to drop, analysts at IHS Chemical conducted a study aimed at helping clients plan despite the new uncertainty. The analysts did not attempt to predict how and when oil prices would recover. Instead, they supposed three possible cases: a short-term, V-shaped recovery; a medium-term, U-shaped recovery, and a longer-term, L-shaped recovery. For each, they analyzed in depth the potential impact on the various petrochemical chains, issuing their findings in a special report, Crude Oil Turmoil and the Global Impact on Petrochemicals.
More than one year into the slump, crude oil prices seem destined for the slowest, L-shaped recovery. In the long-term case, IHS assumes that moderate economic growth will continue for several years, oil demand growth will slow, and technology will continue reducing oil production costs and increasing supply even at lower oil prices. The resulting oversupply could keep oil prices from recovering to trend for more than 10 years, IHS Chemical says.
The implications of the L-shaped recovery include slower growth in US natural gas liquids production and postponed ethane cracker projects, the report says. Results would include a tighter ethylene market, higher operating rates and prices, and increasing market volatility. Ethylene cracker operating rates would be driven to near-record highs since global ethylene demand growth would be strong and the second wave of capacity additions would not come online until 2025.
Naphtha crackers in Europe and Asia would run at high rates in an L-shaped recovery. Their margins would strengthen, and more naphtha crackers would be built in China and other emerging economies, whereas margins for North America’s ethane-based, downstream-integrated producers could shrink by $200/m.t.
Ethylene demand would grow at an average 4.5%/year through 2020, while capacity would grow just over 3%, IHS Chemical says. During 2020–25, ethylene demand would grow an average 4%/year, and capacity would grow under 1%. The result would be severe supply shortages similar to those of the late 1980s, IHS says.
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Clinton Makes Boldest Anti-Fracking Statements Yet in Flint
Mar 7, 2016 | E&E Daily
By Jennifer Yachnin
Democratic presidential primary front-runner Hillary Clinton last night vowed that if she is elected to the White House, she will aim to curb hydraulic fracturing in the United States, asserting that the practice is "not sufficiently regulated."
Clinton, who has previously said she would end fossil fuel extraction on public lands, made the remarks during a two-hour presidential primary debate with Vermont Sen. Bernie Sanders, which was held in Flint, Mich. (E&ENews PM, Feb. 5).
But while Clinton said she would support state or local bans on fracking, she stopped short of endorsing an outright ban on the practice.
Instead, Clinton said she would back regulations that address methane leaks and water contamination, as well as disclosures for chemicals used in fracking fluids.
"So by the time we get through all of my conditions, I do not think there will be many places in America where fracking will continue to take place. And I think that's the best approach, because right now, there are places where fracking is going on that are not sufficiently regulated," Clinton said.
Sanders dismissed Clinton's proposals as too cautious -- "My answer is a lot shorter. No, I do not support fracking," he said -- before pivoting to his own climate change policies, where he is generally seen as more aggressive than Clinton.
"If we don't get our act together, the planet that we're going to leave our children may not be healthy and habitable," Sanders said, pointing to his support for a carbon tax, as well as "massive investments" in energy efficiency and renewable energy sources like wind and solar production.
Sanders reiterated his opposition to fracking when asked whether Democratic governors in states with fracking are incorrect in their assessments that fracking can be done safely.
"This is a national crisis. I talk to scientists who tell me that fracking is doing terrible things to water systems all over this country. We have got to be bold now," Sanders added.
But Sanders appeared to soften his attack on whether Clinton is "in the pocket" of the fossil fuel industry for accepting donations tied to the oil and gas industry via a super political action committee that backs her bid, arguing that his past statements were aimed at addressing campaign finance reform.
In late February, Sanders' campaign touted remarks he made at a Minnesota event, when he said: "Just as I believe you can't take on Wall Street while taking their money, I don't believe you can take on climate change effectively while taking money from those who would profit off the destruction of the planet."
While Clinton declined to discuss a January fundraiser for her campaign organized by the Philadelphia-based firm Franklin Square Capital Partners, which has significant investments in fracking operations, she argued that she has likewise backed ending tax benefits to the oil and gas industry.
"I've already said we are taking away the subsidies for oil and gas, but it is important that people understand that a president can't go ordering folks around," Clinton said. "Our system doesn't permit that. I am going to set the goals. I will push everybody as hard as I can to achieve those goals. We will make progress on clean renewable energy and create millions of jobs through that."
Clinton joins Sanders' call on Snyder
While Clinton and Sanders spent much of the CNN-sponsored debate feuding over trade policy and manufacturing, financial reforms and gun safety, the duo also weighed in heavily on the ongoing drinking water crisis in Flint.
In addition to addressing infrastructure issues in Flint as well as nationwide, Clinton and Sanders focused on how to deal with the fallout from lead poisoning that has affected the city's 100,000 residents.
Clinton also called last night for Michigan Gov. Rick Snyder (R) to resign over the water crisis, echoing demands Sanders first made in January (Greenwire, Jan. 18).
"The governor should resign or be recalled, and we should report the efforts of citizens attempting to achieve that. But that is not enough. We have to focus on what must be done to help the people of Flint," Clinton said.
Flint citizens have relied on bottled water for drinking and cooking under an emergency order first issued last year because of corrosion to lead service lines that allowed the powerful neurotoxin to leach into the city's drinking water supplies.
The corrosion occurred when the city -- under the direction of an emergency manager appointed by Snyder -- switched its drinking water supply to the Flint River in 2014, but the Michigan Department of Environmental Quality failed to add chemicals to the water that would have made it less corrosive.
While both candidates endorsed state and federal funding to address the crisis -- currently stalled in the Senate (see related story) -- Clinton went further, arguing that the federal government should address lead contamination in water, paint and soil.
Clinton said she agreed with a proposal from Flint resident LeeAnne Walters, one of the first individuals to flag the city's lead contamination, who asked both candidates whether they would mandate all public utilities to replace lead service lines within the first 100 days of their hypothetical White House terms.
"I want to go further, though. I want us to have an absolute commitment to getting rid of lead wherever it is, because it's not only in water systems; it's also in soil, and it's in lead paint that is found mostly in older homes," Clinton said. "I want to do exactly what you said. We will commit to a priority to change the water systems, and we will commit within five years to remove lead from everywhere."
Sanders declined Walters' request for a pledge to remove lead service lines but said he would ensure that homeowners would have information on the quality of their drinking water.
"I will make a personal promise to you that the EPA and the EPA director that I appoint will make sure that every water system in the United States of America is tested and that the people of those communities know the quality of the water that they are drinking, and that we are going to have a plan to rebuild water systems in this country that are unsafe for drinking," Sanders said.
Earlier in the debate, Sanders told another Flint resident that he would ensure that city residents would not have to pay water bills for services during the period of contamination, while also asserting that the Centers for Disease Control and Prevention would be tasked with testing every Flint resident for lead poisoning.
"To ease anxiety, [the] CDC has to come in and examine every child and adult in this community in terms of the amount of lead they may have," Sanders said. He then pointed to his $1 trillion infrastructure proposal, adding: "The wealthiest country has to rebuild the crumbling infrastructure, our water systems."
While Clinton criticized both Michigan officials and U.S. EPA for failing to alert residents of the contaminated water, she demurred when asked if she would have immediately fired her own EPA administrator for a similar incident, instead endorsing an investigation into the matter.
"I would have a full investigation, determine who knew what, when, and yes, people should be fired. How far up it went, I don't know. But as far as it goes, they should be relieved [of their duties], because they failed this city," Clinton said.
In response to the same inquiry, Sanders said: "President Sanders would fire anybody who knew about what was happening and did not act appropriately."
More contests follow
Clinton continues to lead in the Democratic primary delegate count, although Sanders claimed victory in three of four Democratic contests over the weekend.
Sanders won caucuses in Kansas, Nebraska and Maine this weekend, while Clinton claimed victory in the Louisiana primary.
On the Republican side, businessman Donald Trump claimed first-place finishes in Louisiana and in the Kentucky caucus on Saturday. But Texas Sen. Ted Cruz added to his own delegate count with wins in Kansas and Maine on Saturday, and a close second-place finish in Louisiana. Florida Sen. Marco Rubio claimed victory in Puerto Rico's Republican contest yesterday.
Voters in Michigan and Mississippi will hold the next round of primary contests tomorrow, and Republicans will also vote in Idaho and Hawaii.
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States, Gas Industry: Feds Do Not Have Power to Regulate Fracking
Mar 7, 2016 | The Hill - E2 Wire
By Timothy Cama
The federal government overstepped its authority by issuing a rule to regulate hydraulic fracturing, according to several states and the gas industry.
In briefs filed in their lawsuit against the Interior Department’s fracking rules, the states and industry groups accuse Interior’s Bureau of Land Management (BLM) of claiming overly broad authority over oil and natural gas drilling on federal land.
“In promulgating the BLM Rule, the BLM insists, for the first time, that it has the authority to regulate hydraulic fracturing on federal and Indian lands,” North Dakota wrote in its brief, adding that when Congress prohibited the Environmental Protection Agency from regulating fracking in 2005, it clearly intended to include all federal agencies.
“Absent a specific grant, the BLM cannot demonstrate congressional intent to alter the more specific provisions of the [laws] or the longstanding balance of power under which North Dakota has primary responsibility over land and water use,” the state said. “The BLM cannot make an end-run around Congress’ clear intent and infringe upon North Dakota’s unmistakable sovereign interest in regulating hydraulic fracturing.”
North Dakota, the other states and the industry groups are asking a Wyoming federal court to overturn the fracking standards that BLM released a year ago, which apply to federal and American Indian land that is leased to energy companies.
BLM wrote the rules in an attempt to update its standards to account for fracking, in which drillers inject fluids at high pressure into wells to break rock formations and release more oil or gas. About 90 percent of the wells on federal land are fracked.
The standards focus on three areas: the integrity of well casing, disclosure of chemicals in fracking fluid and proper disposal of waste fluids.
The briefs filed late Friday are the opening volley in the court fight over the merits of the rule. The regulation is already on hold, thanks to a Wyoming court injunction issued in September.
In their own joint brief in the case, Wyoming, Colorado and Utah said the rule “exceeds the Bureau’s statutory jurisdiction, conflicts with the Safe Drinking Water Act and the Energy Policy Act of 2005, and unlawfully interferes with state hydraulic fracturing regulations.”
The Independent Petroleum Association of America and the Western Energy Alliance used their brief to attack the specific provisions of the rule, saying that BLM showed a clear misunderstanding of the oil and gas industry and didn’t properly account for the costs of its standards.
“Ignoring comprehensive comments in the record detailing the technical and legal problems of earlier proposals, BLM has arbitrarily issued a rule that lacks justification, cannot be administered technically, exceeds the agency’s regulatory authority, and violates federal law,” the industry groups said.
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Week Ahead: Energy Bill, Flint Aid -- Take Two
Mar 7, 2016 | The Hill - E2 Wire
By Devin Henry
Senators are growing increasingly bullish on the prospects of returning to a major energy reform bill and a Flint, Mich., aid package.
Lawmakers negotiating a deal to bring the two items back to the Senate floor say they're trying to resolve final disputes over the packages in hopes of calling them both up for votes in the coming week.
"We need to get it all ironed out, but the thing that I find encouraging every day, and one of the reasons I have not lost my optimism, is because everybody is continuing to talk, continuing to work through things, and as long as all that is happening, you can achieve a desired result," Sen. Lisa Murkowski (R-Alaska), chairwoman of the Energy and Natural Resources Committee, said Thursday.
Murkowski said she expects the energy bill and Flint aid to come back to the floor after senators finish up work on a measure to address opioid abuse early in the week. Sen. Gary Peters (D-Mich.) said the Flint legislation is "hopefully" set to hit the floor after opioid bill is done.
"That's still a work in progress," he said this week. "We're down to very few [complaints]. I don't recall the number, but very few, not many at all."
"We're ready to go, we're ready to vote," Sen. Debbie Stabenow (D-Mich.) added. "We have a great bipartisan proposal. We have bipartisan support. Now it's just a matter of getting the energy bill squared away."
Lawmakers agreed on a $250 million package to upgrade infrastructure for communities across the country struggling with contaminated water, including Flint. The deal opened the door for the Senate to resume considering the energy bill, which faltered last month amid negotiations over Flint, where residents are suffering from a severe lead contamination.
But work both bills has since stalled, with several Republicans placing holds on the legislation. Republican Sens. Mike Lee (Utah) and David Vitter (La.) are both blocking the water agreement, two Senate aides told The Hill this week.
Senators can use holds to stall legislation or a nomination without having to publicly announce their opposition. Lee is reportedly upset over funding levels and Senate procedure and believes the drinking water crisis is a local issue. Vitter said last week he was "quite hopeful" the Senate would soon be able to move forward on the matter.
"There is scheduled to be some people who won't support the overall bill, understand that," Murkowski said. "What we want to try to do is get them to the place where everybody else can express their views and opinions on the overall bill. That's what we're doing, that's what we've been working on."
Off the floor, senators are scheduled to continue examining President Obama's 2017 budget request.
U.S. Forest Service Chief Thomas Tidwell is scheduled to testify on his agency's budget proposal before the Senate Energy and Natural Resources Committee on Tuesday.
The following day, the Environment and Public Works Committee plans to hold a hearing on "EPA regulatory actions and the role of states as co-regulators."
Canadian Prime Minister Justin Trudeau is scheduled to visit Washington for a meeting with President Obama and a state dinner at the White House. Among other issues, the visit will reportedly yield a U.S.-Canada climate change strategy, though American officials have yet to detail what that might look like.
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IPAA's Naatz Says Overlapping State, Federal Regulations Hurting Independent Producers
Mar 7, 2016 | E&E TV
As market uncertainty continues, how are independent producers adjusting to new financial and regulatory dynamics? During today's OnPoint, Dan Naatz, senior vice president of government relations and political affairs at the Independent Petroleum Association of America, explains why he believes more oversight is needed from Congress of the Obama administration's oil and gas regulations, many of which, he says, overlap with state policies.
Monica Trauzzi: Hello, and welcome to OnPoint. I'm Monica Trauzzi. With me today is Dan Naatz, senior vice president of government relations and political affairs at the Independent Petroleum Association of America. Dan, thank you so much for coming on the show.
Dan Naatz: Such a pleasure being here, Monica. Thank you for having us.
Monica Trauzzi: So, Dan, nearly 70 members and representatives of IPAA were in meetings on Capitol Hill last week discussing the specific concerns that independent producers have with the current state of play on regulation. What is the key message that was delivered to members of Congress?
Dan Naatz: It was an important message, that we really do represent the independent portion of the upstream sector of the oil and natural gas industry. And so we went to Congress to have a discussion of the regulations that are coming from the administration, the impact that it has on our members, the impact it has on natural gas and oil production on federal lands, on private lands, and everywhere, and really concern about the number of kind of regulations that are pancaking on top of each other. So that was the message we brought to Congress this week.
Monica Trauzzi: Some of your members met with House and Senate leadership. What is the policy landscape that they laid out for you, and what is it that Congress can do when it comes to these regulations?
Dan Naatz: Yeah, it's a great question, and it was something that our members struggled with, to say, you know, it's not necessarily passing a specific bill or doing anything. So one of our real focuses was oversight, both in the House in the Senate, to have the committees, both Republican and Democrat, on a bipartisan, ask the administration questions about this. What is their purpose? Because many times we've found that regulations overlap, they overlap with state regulations, other federal regulations, and so as you're moving forward -- certainly for our members -- looking at this complicated regulatory scheme, we need the Congress to get some of those answers from the administration.
Monica Trauzzi: Is your sense that there is a clear understanding from members of Congress about why things are different for your producers versus the bigger guys?
Dan Naatz: Yeah, there is. I think again -- and we represent a wide swath of members, but I do think a lot of these members understand that the independent producers, our average size is still a 20-person company. When you're talking about having to navigate this complicated regulatory scheme, it is different for those companies. And again I also want to stress -- and we always lead with that -- we're very proud of our environmental record. We're very proud of our safety record. But when you're looking at it, it is a challenge for smaller companies to address those concerns.
Monica Trauzzi: This is a particularly volatile and uncertain time for the oil industry. How are your producers affected by market dynamics?
Dan Naatz: Market dynamics are -- you know, no doubt it's a tough time in the industry. You've seen this -- in one way the renaissance that's happened with American oil and natural gas production has really led to lower prices and this price environment. But those are challenges a couple of our members that I was with on my team said, "Look, we understand that. We've faced that over the years -- a boom and bust cycle. We can plan for that. As a good businessman you should plan for that." The challenge we have is that currently the regulatory scheme, the legal system that's happening is really forcing them to have to make decisions outside of the business cycle that they face with prices and commodity prices.
Monica Trauzzi: And IPAA's CEO Barry Russell recently wrote in the Washington Times that the Obama administration's oil and gas policies are sapping the strength of energy producers. There's data showing production is back to pre-Deepwater Horizon levels, so what specific changes then would your industry like to see on the regulatory front? You talked about this pancaking. What would you like to see?
Dan Naatz: I think one of the issues is clarity, in addition uniformity, so that you know the scheme you're facing before you go forward. Second of all, in Barry's article I think the discussion is certainly on state and private lands you've seen this uptick in oil production, natural gas production, but on federal lands where the federal government has an integral role, that has all dropped. And we view it as an opportunity for the federal government to step forward and have a wide array of options moving forward, and one of those options we're concerned about is to continue to push for keeping it in the ground on federal lands. And that's a challenge for a lot of our members who operate both onshore and offshore, quite honestly.
Monica Trauzzi: The Obama administration recently proposed directing oil and gas revenues from offshore production towards climate resilience. Do you believe that more funds should be going to climate resilience?
Dan Naatz: You know, one of the issues is there's going to need to be additional research and review of all these issues. And we are -- as producers we often talk about the royalties that go to the federal government. I won't get into too many details on where that goes -- there's issues of land and water conservation funds, should the monies go elsewhere -- but it does get to the point that these are federal revenues. It's an important revenue stream for the federal government and something that we have always been very proud of what we've done and think we can contribute more if we have the opportunity, rather than go the opposite direction.
Monica Trauzzi: So when you look at the current field of potential nominees to become the next president, is there one candidate in particular that you think would serve the interests of your industry best?
Dan Naatz: We have not taken -- on the presidential level we have not taken any position on that, and we won't do that. But we certainly review all the candidates, and over the years -- I've been now at IPAA for 13 years -- every presidential election we'll meet with both the candidates and their teams, talk about what we have done, again both on a bipartisan fashion. We met with the Obama administration; we met with the Romney folks last time. We'll continue to do that, because one of the things I think that is important for the country to have is a discussion on energy where we go -- this renaissance, not only in oil and natural gas, but the unbelievable opportunity that's been created as we're talking about oil imports going down to the lowest level in decades. Again, not only that, but wind, solar -- how this all works is going to be key to having a vibrant economy, to increasing job growth, and certainly for the next 10, 15, 20 years where the nation's going.
Monica Trauzzi: All right, we'll end it right there. Dan, thanks for coming on the show.
Dan Naatz: Monica, thank you very much.
Monica Trauzzi: And thanks for watching. We'll see you back here tomorrow.
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A Call for College Students to Help Shape Their States’ Clean Power Plans
Mar 6, 2016 | New York Times
By Andrew C. Revkin
Back in January, Eban Goodstein, the director of the Bard College Center for Environmental Policy, distributed an invitation to college students and faculty across the United States to participate in “Power Dialog,” an exciting effort to mesh learning and civic engagement around the nation’s efforts to curtail power plant emissions of carbon dioxide, the main human-generated gas contributing to global warming.*
The focus is the Obama administration’s Clean Power Plan. Despite the Supreme Court ruling delaying the plan, not to mention the turbulent presidential race, the plan’s mix of regulation and regional flexibility is likely to persist well into the future. The academic effort, which is nonpartisan, centers on a nationwide series of meetings in state capitals April 4 in which students can offer their views to top state officials.
Goodstein, in an email on Sunday, said the focus has broadened since the Supreme Court ruling. “The Power Dialogs are now focused on what states can do to support the U.S. Paris climate commitment,” he said. “There are multiple policies supporting renewables and energy efficiency in many states, red and blue. This is a chance for students to learn about solutions, instead of being demoralized by partisan gridlock.”**
There’s a map here with locations. You can sign up here. But there’s plenty happening between now and then, including a series of online seminars. The next one, Wednesday, March 9, will be by Alex Barron of Smith College and formerly the Environmental Protection Agency. He’ll speak about “Job and Economic Impacts of the Clean Power Plan.”
The Bard website has much more information on the events, as well as background links and readings.
Here’s the note introducing the effort, which came from Goodstein and three prominent environmental leaders, Bill McKibben, Hunter Lovins and Gus Speth:
Know a college student or a teacher? Then you can help 10,000 students around the country, and hundreds in your own state, change their future.
The week of April 4, 2016 The Power Dialog is organizing conversations in every state capitol between students and the top regulators in their state charged with reducing global warming pollution under the E.P.A.’s Clean Power Plan. The E.P.A.’s new rule is the main vehicle enabling the 30 percent cuts in pollution pledged by the U.S. in Paris.
But so far, the regulators drafting statewide pollution reduction plans have not heard from their most critical stakeholders: young people who will actually be around in 2050, living through the consequences of our action — or inaction — today.
The Power Dialog gives young people that vital voice.
The model is simple. Faculty teaching courses in environmental studies, energy, climate change, environmental politics, economics, or sociology include material on the Clean Power Plan. They then bring their classes on field trips to the state capitol for the Dialog. Students reach out to their faculty to insure their classes are included. With fifteen to twenty college, university or high school classes involved in each state, hundreds of students statewide will have the chance to get educated about the Clean Power Plan. Then, they engage directly with their state’s top regulator about cutting global warming pollution locally.
The Power Dialog, organized nationally by The Center for Environmental Policy at Bard College, is not an advocacy or lobbying project. There is no legislative agenda. Rather, the goal is simply to educate thousands of young people about the emerging new rules for climate protection, and to give them a chance to talk face-to-face with the state regulators who are shaping their future.
So here’s the easy and effective way you can help. Pass this post along to the students, faculty and educational staff you know to build the Power Dialog in their state. Our country, and our world, critically need the voices of 10,000 engaged young people next April, and beyond.
Do this now, and get your year changing the climate started strong. Lots more opportunities to come.
You can also keep track and spread the word via @thePowerDialog on Twitter: Are Students a Missing Voice on Climate Post-Paris? Not any more: @BardCEP @ThePowerDialog #SCOTUS#CleanPowerPlan
http://3bl.me/kthsp8Here’s a related 2015 post on a Pace University dialogue focused on New York’s clean-energy options: “Charting Clean-Energy Paths in New York and Beyond.”
And I couldn’t help notice how the Power Dialog is echoed at the high school level by Change Climate Change, an initiative by some students at the Marlborough School in Los Angeles aiming to engage with government officials shaping their city’s energy and climate policies. In an email a few days ago, Clara Nevins, a tenth grader there, asked this question:
We are able to organize hundred of students to write to politicians, capitalists, or other decision makers to express the concerns of the next generation about climate change. Our problem is that we don’t know exactly how to harness this energy…who to write to and about what specific piece of legislation or reform.
Please help Clara with some ideas. (And read the post she wrote after going to Paris for the climate treaty negotiations last December: “A Millennial’s Take on Climate Activism.”)
I’m a big fan of simultaneously learning and doing.
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Indian Point: Past Its Expiration Date
Mar 7, 2016 | New York Times
By Paul Gallay and Michael Shank
Last month, samples showed a spike in the amount of radioactive tritium being discharged from Indian Point Energy Center into the groundwater near our homes along the Hudson River. Gov. Andrew M. Cuomo ordered several state agencies to carry out an inspection of the nuclear plant just 45 miles north of midtown Manhattan; the Nuclear Regulatory Commission also sent inspectors.
This radioactive spill is far from the first malfunction at Indian Point,which opened over 50 years ago. In the last year alone, Indian Point has suffered seven major malfunctions — pump and power failures, a transformer explosion, radiation leaks, a fire and an oil spill. Governor Cuomo has ordered a further, full investigation and now says that all these accidents demonstrate that Indian Point can no longer operate safely.
We agree. Malfunctions can happen at any power plant, but they are happening with disturbing frequency at Indian Point. Its age is problematic, and its safety is doubtful. The licenses for Indian Point’s two reactors expired in 2013 and 2015; the Nuclear Regulatory Commission is still weighing whether to renew them.
In 2007, Barack Obama called the commission a “moribund agency” that was a captive of the industry it regulated. It still looks that way today.
The commission seems to accept the word of Indian Point’s operator, Entergy, that basic safety and environmental cleanup measures aren’t necessary, even after the latest mishaps. The commission even permits Indian Point to evade its own safety standards requiring that the electrical cables that control emergency reactor shutdowns have insulation that would last 60 minutes in a fire — giving the plant an exemption after finding that this insulation lasted just 27 minutes.
Poor maintenance at Indian Point has caused groundwater radiation levels to soar to 740 times federal limits, yet the commission just handed Entergy a five-year delay of the deadline for testing for possible leaks from the No. 2 reactor — the suspected source of this latest leak of radioactive contamination. The commission admits that tritium in the groundwater will reach the Hudson River and that the radioactive isotope, for which there is no safe dose, can cause cancer.
Indian Point also has about 1,500 tons of radioactive waste in the form of spent fuel rods packed into pools. These, too, are leaking radiological contamination that violates the Clean Water Act. In addition, the plant’s cooling system has devastating effects on the Hudson’s ecology, killing more than a billion fish, eggs and larvae each year as it draws millions of gallons of water per day from the river.
The commission has reported that one of Indian Point’s reactors has the highest risk of all the country’s reactors of being damaged by an earthquake, and federal studies show that Indian Point is incredibly vulnerable to acts of terrorism. Tens of millions of people live within the reach of an Indian Point nuclear disaster. An evacuation would be practically impossible and emergency responses would be largely futile.
A recent poll in the Lower Hudson Valley found that a majority of respondents do not trust the plant’s safety or its operator. The fact is that we have enough power capacity to permit the immediate closure of Indian Point.
Indian Point is able to generate just over 2,000 megawatts of electricity, or about 10 percent of peak summer demand in the New York metropolitan area. According to Riverkeeper’s calculations, however, we already have an additional 1,500 megawatts of energy capacity from other sources: existing electricity surpluses in New York State, recently restored power generation from plants in the Hudson Valley and New York City, together with transmission improvements in the power grid in the lower Hudson Valley and targeted energy efficiency gains by Con Edison.
The New York Independent System Operator, a nonprofit agency charged with managing the state’s electricity market, indicated in a report last year that there would be a net reliability “need” of 500 megawatts if Indian Point was to shut down before this summer. Since that study, though, downstate load forecasts for this summer have dropped by about 500 megawatts, thanks in part to increases in solar power installations.
In short, we can close Indian Point now and reliably keep the lights on. In the future, new efficiency and renewable energy projects will drive still greater savings, thanks to $5 billion in planned energy investments by the state.
We no longer have to rely on this aging, unsafe nuclear plant. The Nuclear Regulatory Commission should cancel Indian Point’s operating licenses immediately and start overseeing an orderly closing.
Paul Gallay, a former lawyer for the New York Department of Environmental Conservation, is the president of Hudson Riverkeeper, where Michael Shank is a communications fellow.
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Utility Regulators Practice 'Diabolical' Digital Hostage Crisis
Mar 7, 2016 | E&E Energywire
By Blake Sobczak and Peter Behr
A new class of kidnapper is polite and reliable and even provides online customer support.
The courtesies and convenient payment methods are of little comfort to victims of "ransomware," a nasty type of malware that locks up computer files and holds the key hostage.
As ransomware spreads to police departments, government offices and even hospitals, energy utilities and their regulators have weighed the consequences of an attack on critical infrastructure.
Miles Keogh, director of grants and research at the National Association of Regulatory Utility Commissioners, devised a cyber challenge for state regulators to rehearse at a recent meeting in Washington, D.C. The fictional scenario infected several regional gas, water and electric utilities with ransomware and then asked participants to think about whether they would pay up -- and at what price.
"One thing we wanted to illustrate is that utilities actually are in possession of a lot of juicy data that bad guys would want to grab," Keogh said.
The risk from ransomware campaigns with names like "CryptoLocker," "Locky" and "KeRanger" differs from the more existential threat of a country like China or Russia aiming destructive malware at the U.S. power grid.
"The nation-state," he said, "they don't really have a motive to take down the grid or to attack water systems or gas systems," Keogh said.
"What ransomware does is it monetizes the attack," he said. "And if you're trying to figure out a diabolical challenge to our utility infrastructure, it solves your motive problem."
It also raises a host of other problems -- whom should utilities call if they're hit with ransomware? Can they hope to recover the costs after a "Locky" attack? Would companies opt to just pay the ransom?
Last month, a Los Angeles-area hospital decided to cough up $17,000 in bitcoin digital currency after its medical records were locked up by hackers. That case at Hollywood Presbyterian Medical Center was "the obligatory canary in a coal mine," cybersecurity professional Angel Grant of RSA said in a recent blog post.
While there are no documented cases of ransomware hitting electric or gas utilities to date, there are signs that hackers now have the sophistication needed to go after better-defended networks.
Christiaan Beek, who manages threat intelligence research at Intel Security, told EnergyWirehis team has unearthed evidence of a targeted, more careful ransomware attacker. Rather than breaking into computers through phishing emails designed to lure users into clicking a malicious link, the actors behind the new ransomware campaign search for vulnerabilities on Web servers and exploit them. Next, the hackers take time to learn about each network they crack, taking care to avoid detection.
"They started with the smallest files first, so if you would kill the process on the system, at least many, many files would have already been encrypted," Beek said.
"These guys really understood their game," he added. "They have the guts, they have confidence and they have the time."
The payoff? Precise totals are unknown, but past ransomware campaigns have netted hundreds of millions of dollars for hackers who are often able to remain in the shadows.
'We're crawling right now'
The made-up attackers in Keogh's example were similarly skilled, using an advanced injection package to get ransomware onto the victims' computers. They later leveraged a "botnet" of enslaved computers to seek and exploit flaws on the utilities' operational networks, bringing ransomware to the industrial control systems that help keep natural gas flowing and the lights on.
A group of state regulators, state energy directors and utility executives met one afternoon last month to discuss NARUC's ransomware attack scenario. Under the meeting's rules, reporters were allowed to listen to the discussion but not to identify participants or their organizations.
There was little support in the room for paying ransomware, even though the cost of damage done from not paying it might leap higher than the ransom demanded, as several speakers acknowledged.
"It's the same reason the federal government doesn't negotiate with kidnappers," one state energy director said -- paying out would only encourage more attacks.
Several utility officials and regulators preferred the option of buying insurance against a cyberattack. But other speakers cautioned that some policies might not cover an attack that was linked to a state-sponsored or -supported malware campaign. "You have to look closely at exclusions. If it's a nation-state, that's probably excluded," one regulator said.
Speakers moved beyond the ransomware issue to the need to coordinate recovery operations in the event of a major cybersecurity and physical attack on the grid that extended across utility boundaries. They indicated the industry and government agencies are a long way from the closely coordinated response power companies routinely make to major storm outages.
The Electricity Subsector Coordinating Council, comprising power company chief executives who meet with top-level federal law enforcement and intelligence officials, has begun to define what a cyber mutual assistance agreement in the electricity industry would look like, said one senior official in the meeting.
"It's a crawl, walk, run process," the official said. "We're crawling right now."
Mutual assistance typically is covered by legal documents allowing power companies to call for help. "Does it work if you substitute 'network defender' for lineman?" Keogh asked. The answer isn't clear, speakers said.
The utility officials and regulators acknowledged that coordination plans among states and across critical service sectors are embryonic, at best. In a major crisis, two adjoining states could compete for the same emergency help. "There is no hand at the top to determine who gets what," one participant said. "Who gets help first may depend on where CNN is," another said.
Preventing a lockdown
Beek of Intel Security said simple cybersecurity hygiene -- frequently backing up files, making sure programs such as Flash Player are up to date -- can go a long way toward fending off ransomware.
Researchers agree that once hackers lock up files and throw away the key, there isn't much recourse, suggesting you "may as well have dumped your PC over the side of a bridge."
Most varieties of ransomware rely on 2,048-bit public key cryptography, a system that is next to impossible to break if implemented properly. A normal laptop would need to run nonstop for longer than the age of the universe to find the private key to unlock files via "brute force" computer guessing.
So utilities would be advised to prepare their cyber defenses and expenditures before they're locked out of their own files, as Keogh pointed out.
"It definitely illustrates the fact that you can't make these protective investments retroactively," Keogh said. "They need to be made ahead of an event -- you simply can't manage this by chasing a problem that already happened."
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Refinery Fire Causes Temporary Closure of Houston Ship Channel
Mar 7, 2016 | E&E Energywire
By Nathanial Gronewold
An explosion at a Texas refinery linked to a Brazil oil industry scandal closed one of the busiest U.S. ports over the weekend, but the impact was brief.
Saturday morning brought reports of an explosion and fire at a facility operated by Pasadena Refining System Inc., triggering a closure at the Houston Ship Channel. The channel is home to Texas' largest port and a major conduit for trade in petrochemicals, refined products and now crude oil exports as well as imports.
The Coast Guard later reopened the port after establishing a safety zone around the accident scene, barring ship traffic from nearing the emergency response zone. Hazardous materials teams were dispatched to the scene.
One injury was reported.
The Coast Guard and Harris County responders reported no signs of contamination in the channel's waters. The closure of the port was too short to have caused any meaningful impact to trade.
"Coast Guard hazmat teams were able to investigate the scene for any impact from possible chemical release in the air or any impact on the waterways," Coast Guard public affairs said in an email.
The refinery is believed to be one piece in the chain of corruption scandals roiling the Brazilian government-owned Petróleo Brasileiro SA oil and gas conglomerate. The Houston Chroniclereported in November that investigators suspect that officials at Petrobras purchased the facility at a grossly inflated price in an elaborate kickback scheme.
The explosion is also the latest accident centered on the Port of Houston region, home to the nation's largest refining and petrochemical complex. A barge collision in 2014 shuttered the Houston Ship Channel for a week as response teams scrambled to clean up some 170,000 gallons of heavy fuel oil that spilled in waters right next to a major shorebird flyway.Email: ngronewold@eenews.net
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Potential Obama Picks are Seasoned Regulatory Referees
Mar 7, 2016 | E&E Greenwire
By Robin Bravender
Two more high-profile federal judges with experience deciding environmental cases are reportedly being vetted by the White House for the Supreme Court vacancy.
Judge Sri Srinivasan and Chief Judge Merrick Garland of the U.S. Court of Appeals for the District of Columbia Circuit have been the subjects of FBI background checks, The New York Times reported. The two appeals court judges have been widely cited as potentially attractive picks for President Obama as his administration looks to circumvent staunch Republican opposition to any nominee before the November presidential election.
Obama appointee Srinivasan, 49, and Clinton appointee Garland, 63, were both confirmed with Republican support. Srinivasan was confirmed unanimously in 2013 by a 97-0 Senate vote. Garland was confirmed 76-23 in 1997; when he was discussed as a possible Obama Supreme Court nominee in 2010, Republican Sen. Orrin Hatch of Utah told Reuters that Garland "would be very well supported by all sides."
Srinivasan faced some opposition from greens in 2013 when he was under consideration for the D.C. Circuit.
EarthRights International urged senators to oppose his nomination, complaining about work he did for Exxon Mobil Corp. as a partner at the law firm O'Melveny & Myers. Srinivasan at the time was among the lawyers representing the oil firm in a case surrounding alleged human rights violations in Indonesia. Exxon argued it was immune from liability under a law that allows federal courts to hear human rights claims filed by citizens of other countries.
"Mr. Srinivasan's record shows a commitment to serving corporate persons, rather than making the law work for real people," EarthRights International said in 2013. The group, however, has since reconsidered its position after evaluating Srinivasan's record on the D.C. Circuit, wrote Marco Simons, Americas Regional Program director at EarthRights International. "We're not endorsing any candidates for the Supreme Court, but we do not oppose Srinivasan's nomination, although we continue to believe the Senate should receive full information about his work as a government lawyer that may have benefited his former corporate clients," he wrote last month on the group's website.
Since joining the D.C. Circuit in 2013, Srinivasan has made a series of pro-environmentalist moves.
Most recently, he was on a panel of judges that rebuffed requests to freeze the administration's Clean Power Plan. That decision was overturned by the Supreme Court last month when the justices decided to step in and halt the rule, but litigation over the rule to limit power plants' greenhouse gas emissions is continuing in the D.C. Circuit. Srinivasan is slated to be on the three-judge panel that hears arguments in that blockbuster lawsuit in early June.
In a 2014 ruling from a divided court, Srinivasan wrote a majority opinion siding with environmentalists over EPA. He found that the agency had acted illegally in 2008 by extending a compliance deadline for areas to meet an air quality standard for ozone (Greenwire, Dec. 23, 2014).
Srinivasan and Garland both ruled in 2014 that environmentalists could challenge an Interior Department decision that would allow coal mining at the site of a historic 1921 coal miner uprising in West Virginia. The opinion, written by Srinivasan, found environmentalists had legal standing to challenge the decision because they had shown their injury was concrete and imminent. A Republican-appointed judge on the panel dissented from the opinion (Greenwire, Aug. 26, 2014).
Also in 2014, Srinivasan sided with EPA in a lawsuit from states and the mining industry that took aim at Obama administration policies cracking down on mountaintop-removal coal mining. In that opinion, Srinivasan signed on with two Republican-appointed judges to uphold policies that imposed stricter rules for addressing water contamination near mining operations (Greenwire, July 11, 2014).
Garland called 'model, neutral judge'
With nearly two decades on a court that frequently referees fights over federal agencies' rules, Garland has an even longer track record on environmental cases.
When Garland's name was being floated for the high court in 2010, Supreme Court watcher Tom Goldstein called him the "model, neutral judge" who is "acknowledged by all to be brilliant" and had "broad support on both sides of the aisle." The White House instead nominated Elena Kagan to replace retiring Justice John Paul Stevens that year.
Assessing Garland's record in 2010, Goldstein wrote on the website SCOTUSblog that the judge had "strong views favoring deference to agency decisionmakers." Goldstein said environmental law, however, is "in fact the area in which Judge Garland has been most willing to disagree with agency action." On environmental law, Goldstein wrote, "Judge Garland has in a number of cases favored contested EPA regulations and actions when challenged by industry, and in other cases, he has accepted challenges brought by environmental groups."
Recently, Garland was on a three-judge panel that upheld EPA's mercury standards for power plants in 2014. That rule was later knocked down when the Supreme Court ruled EPA hadn't properly considered costs, and the D.C. Circuit sent the rule back to the agency to bring it in line with the ruling (Greenwire, Dec. 15, 2015).
Also last year, Garland joined his colleagues in rejecting a challenge to the Interior Department's plan for oil and gas leases on the outer continental shelf (Greenwire, March 6, 2015).
If either of the D.C. Circuit judges is named as Obama's nominee, his judicial record is certain to come under further scrutiny.
Among the other federal judges reportedly being vetted by the White House is Judge Ketanji Brown Jackson of the U.S. District Court for the District of Columbia, a 45-year-old African-American judge who's related to House Speaker Paul Ryan (R-Wis.) by marriage (Greenwire, March 2). Judge Jane Kelly, 51, whose nomination to the 8th U.S. Circuit Court of Appeals was supported by Senate Judiciary Chairman Chuck Grassley (R-Iowa), has also reportedly been under consideration (Greenwire, March 3).
Political sparring continues
The Obama administration hasn't yet announced when a nominee will be named.
White House spokesman Josh Earnest last week declined to comment on any meetings with candidates for the job but said officials continued to review material about potential nominees.
"At this point, I don't have additional timing guidance to share," Earnest told reporters Friday. "I think the things that we have acknowledged is that the two previous vacancies -- that nominees for the two previous vacancies were announced about four or five weeks after those vacancies occurred." Obama wrote in late February that he would make an announcement in the coming weeks.
Meanwhile, the political battle over whether Obama or the next president should name the nominee continues to play out in the media.
Vermont Sen. Patrick Leahy, the top Democrat on the Senate Judiciary Committee, wrote apost on SCOTUSblog yesterday criticizing his Republican colleagues for pledging to hold up Obama's nominee.
"Unfortunately, eleven Republican Senators are trying to deny a full and open debate on the next nominee to the Supreme Court -- BEFORE that individual has even been named," Leahy wrote.
He went on to accuse his Republican colleagues on the committee of unilaterally deciding against considering a nominee this year in a "closed-door, backroom meeting in the Capitol," a meeting "closed to press, to the public, and to Democratic senators who serve on the Judiciary Committee."
Ahead of his meeting with Obama last week, Grassley wrote his own post on SCOTUSblog, pledging that "Senate Republicans will ensure the American people are not denied" the "unique and historic opportunity" to impact which political party picks the next justice when they elect the next president in November (Greenwire, March 1).
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Clean Coalition: How Utilities and Greens Teamed up to Pass Oregon's 50% RPS
Mar 7, 2016 | Utility Dive
By Herman K. Trabish
The story behind Oregon’s just-passed 50% renewables mandate contains lessons for states across the country.
Senate Bill 1547, which also will move Oregon’s investor-owned utilities Pacific Power and Portland General Electric (PGE), completely off coal by 2035, was the result of a collaborative effort from the IOUs, the state consumer advocate, and a group of environmentalists and renewables advocates.
Once it is signed, that effort will have produced a law that represents "the single greatest step any state has taken on climate change in the wake of the historic Paris agreement in December,” according to Sierra Club Sr. Campaign Representative Amy Hojnowski.
This joint effort is an example of a recent trend in power sector policymaking in some states. Instead of battling over changes to the utility power mix in contentious regulatory proceedings, stakeholders work toward a win-win solution in outside meetings, presenting a united front to legislators and regulators alike.
An early example of the trend was when South Carolina’s solar advocates joined with Duke Energy and South Carolina Gas and Electric in 2014 to writelandmark policy that is already growing the state’s solar capacity. A more recent instance is in Maine, where the consumer advocate and local solar installers are now working with utilities and state lawmakers to write an entirely new kind of solar support policy.
Those policymaking efforts stand in contrast states like North Carolina, wherestakeholders have rejected working with Duke Energy and have made little progress on solar policy, and Nevada, where the clash between solar advocates and NV Energy has all but shut down the state's solar business.
Following expected approval from Gov. Kate Brown (D), the Oregon bill will set one of the most aggressive U.S. renewable portfolio standards (RPS) “matched only by California and New York, which have a 50% target by 2030, Vermont, which has a 75% target by 2032, and Hawaii, which has a 100% target by 2045,” said Stoel Rives Partner Jennifer Martin.
Under threat of facing a ballot measure on renewables and coal use that garnered wide support from Oregonians, the utilities chose to negotiate with the environmentalists on the just-passed bill, said Angus Duncan, chair of the Oregon Global Warming Commission. The resulting legislation raises the state’s current 25% renewables mandate by 2025 to 50% renewables by 2040.
It also requires the IOUs “to stop accepting deliveries from coal plants as those plants hit their depreciation completion dates,” Duncan said. “Most Pacific Power and PGE plants have depreciation dates in the 2020s and but one out-of-state PGE plant will go until 2035, so by 2040 Oregon should be at 70% to 90% zero carbon electricity.”
But despite support from a variety of power sector stakholders, not everyone is satisfied. Utility regulators in Oregon and elsewhere have spoken out against the bill, saying it will raise consumer prices without directly resulting in the shutdown of coal plants or reductions in CO2 emissions.
The bill provisions
Besides the new mandate and coal phase out required of the two IOUs, which serve 70% of Oregon’s electricity needs, Senate Bill 1547 requires the IOUs to get to 27% renewables by 2025, 35% by 2030, 45% by 2035, and 50% by 2040.
The bill adds to requirements encouraging the IOUs to support community-scale renewable projects, including local wind and solar, small hydro, biomass, and geothermal resources. It also changes current law and counts pre-1995 biomass plants and associated co-generation toward the higher renewables mandate.
The bill keeps in place consumer protections in the current mandate, most notably a 4% cap on the maximum premium IOUs can pay for mandate-compliant renewables, according to Pacific Power Spokesperson Ry Schwark. That provision has kept IOU costs down as they pursue the current 25% renewables mandate, and Schwark expects it to continue to do so.
The bill also allows the Oregon Public Utility Commission to temporarily suspend the RPS if grid reliability is threatened. Other PUC-requested language protects ratepayers from post-2030 costs.
To help the IOUs make the transition away from coal, the bill sets the life of newly-acquired Renewable Energy Certificates (RECs) at five years and grants the utilities’ currently-banked RECs the unlimited life established in the existing mandate.
To drive early investments by the IOUs and take advantage of federal tax credits make wind and solar, RECs acquired by the IOUs before the end of 2022 would also have unlimited life.
The bill orders the PUC to establish Oregon’s first rules community solar. It also calls for supports for more electric transportation, including a requirement that the PUC consider Pacific Power and PGE proposals for deploying and rate-basing electric vehicle charging stations and other EV infrastructure.
The bill also calls on the PUC to continue considering IOU proposals for cost-effective energy efficiency and demand-response resources and to place approval of them ahead of authorizing spending on new generation.
Finally, it protects against possible efforts by some large utility customers to escape the new mandate by moving away from their current IOU, electric cooperative, or public utility, and buying hydropower directly from theBonneville Power Administration.
Stakeholder collaboration
Members of the SB 1547 coalition largely agree that the process on the current bill began when a piece of earlier legislation — 2015's Coal to Clean bill — got stopped in committee.
That bill would have required utilities to stop purchasing power from coal plants by 2025 and replace that power with resources that are at least 90% cleaner in terms of carbon emissions. The utilities opposed it and the bill died in committee.
After the bill failed to move forward, Renew Oregon started a ballot measure with the same goals, said Communications Director Brad Reed.
In support of the ballot measure, Renew Oregon, Sierra Club, Renewable Northwest, the Consumers Utility Board, and other environmental groups created a statewide campaign and a broader coalition. After a year of community organizing and educational outreach, polls showed about seven of 10 Oregonians favored the ballot proposal.
"That brought the utilities to the table," Reed said.
The environmental groups did not engage the utilities on ill-fated Coal to Clean bill, recalled PGE Public Policy VP Dave Robertson. He and Pacific Power’s Scott Bolten sent letters to the environmental coalition in May 2015 proposing a collaboration they said would begin after the EPA's Clean Power Plan was finalized in August of last year.
Meetings didn’t begin until after the groups had filed the ballot measure.
“We thought the discussion would take most of 2016, but the ballot measure put some urgency to the discussion,” Robertson said. “The imperative became whether we could get to an agreement in time have the environmental groups withdraw the ballot measure.”
The utilities were prepared to fight the ballot measure “but it would have been an uphill battle,” Robertson said.
The environmental groups "smartly picked two issues — coal and renewables — that the public would support them on," the utility executive said. "We thought that measure could pass and we thought we could collaborate on a package that has more flexibility for the utilities, more consumer protections, and more protections for system reliability.”
Once the negotiations started, the utility representatives began to think about what a low carbon economy looks like and where they fit into it, Reed said. “Our two big utilities became clean energy champions.”
There was, however, an important prelude to these events.
“Five years ago some of the same people negotiated a deal with PGE in which they committed to closing the only in-state coal plant by 2020,” said Duncan. “We helped get them a deal with our air regulators that cost them $50 million to comply with the Clean Air Act but avoided a $450 million investment in further upgrades."
"That deal created the basis for mutual confidence for this deal," Duncan said.
Consumer Utility Board Executive Director Bob Jenks added that he had been floating the possibility of such discussions to the utilities “for a couple years.”
When the talks finally began, he said, it was challenging. The environmental groups did not initially understand utility regulation and the limits it imposed. But once the coalition agreed on the increased mandate and the coal phase out, “the rest was details,” he said. “If all the participants accept common goals, it is not that hard to work out details.”
The IOUs needed their partners to ease the ballot measure’s "steep" and "aggressive" changes and consider providing incentives instead of just requirements, Robertson said.
“It is not everything we wanted. That is the how compromises are. But we got most of the way there,” he said. “Having some certainty is important for utilities as we make long term capital decisions. But details matter, too, and we all dug into them."
The utilities were able to get modifications in the years the mandate steps up that more closely match their projected power needs, he said, meaning they will not be forced to build new renewable capacity before they need it. They also were able to get the REC modifications.
“We added the provision for lifetime RECs for early building of renewables within the first five years of the mandate,” Robertson said. “The environmentalists wanted to mandate more renewables in early years. We suggested there be incentives to build renewables earlier. That was a compromise we created for this bill. It encourages early action on renewables instead of forcing us into it.”
“The lesson is that these things can be talked through and solutions are possible, solutions that are good for the environment, provide the certainty utilities need, and are good for ratepayers,” Reed said.
“It was a collaborative effort between groups that wouldn’t normally sit down together,” said Renewable Northwest Director of Communications Cliff W. Gilmore. “You have to be willing to listen to people with completely different points of view.”
The regulators' criticisms
Along with increased stakeholder collaboration, the Oregon mandate is a part of another trend, National Association of Regulatory Utility Commissioners (NARUC) President Travis Kavulla recently told Utility Dive. In the face of mounting uncertainty surrounding the Clean Power Plan after the Supreme Court put a judicial stay on the carbon legislation last month, some states are looking to boost their committments to clean energy and decarbonization.
In the Oregon legislation, environmentalists exchanged “an increase to the renewable portfolio standard and a notional commitment to cease the importation of coal power,” Kavulla said. In return, utilities are permitted “risk free investments, repayment for all of the risk and stranded costs of their investments in coal plants…[and] a retrenchment of their monopoly position of the market.”
A cap and trade program or a carbon tax might be more ideal for Oregon “but it is very hard to make the politics work for either,” Duncan said. “The solution the environmental community came to was a ballot measure.”
Controversy erupted as SB 1574 neared a final vote. Oregon Public Utility Commission (PUC) Chair Susan Ackerman testified to lawmakers that the bill “will be both costly and ineffectual because it will raise customer rates but it won’t reduce the amount of carbon emitted because it is just an accounting mechanism.”
SB 1547 “doesn’t change which coal plants operate or how they operate so it does nothing about emissions,” Ackerman said. “Utilities acknowledge the bill costs consumers but doesn’t do anything for the environment.”
What Commissioner Ackerman meant was that the bill “doesn’t mean coal doesn’t keep getting burned in them after 2030,” Duncan said. “The electricity from those fully depreciated plants would be lower cost. Oregon ratepayers would be paying more for new renewables and electricity from the old coal plants would be re-dispatched."
The PUC’s conclusion is the plants’ owners will continue to operate them and sell the power into the wholesale markets, Ackerman said. The price to ratepayers will go up because the new, more expensive renewables generation will go onto utilities’ books and less expensive electricity generated from fully depreciated coal plants will go off their books. In short, the bill offers “the most expensive way to reduce carbon emissions,” she said.
While Duncan agrees with the logic, he said the regulator's concerns may prove to be a bit overblown.
"It is technically true these plants could re-dispatch to other loads," Duncan said, "but there is no guarantee they will, and some evidence [shows] that it is unlikely.”
Ackerman also expressed concerned about the high penetration of renewables mandated in Oregon while neighboring California is taking on a similar challenge.
“No one knows how it will turn out. WECC studied high penetrations of renewables and concluded that at a 30% RPS in the Pacific Northwest, there starts to be significant periods of over-generation," she said. "I suspect there will be times when there is a lot of energy that will have to be dumped.”
Better studies might have been pivotal in the decision, Ackerman said. But the utilities leapt at the opportunity to negotiate a better deal than the ballot measure. That left no time for study and deliberation.
The legislation does call for some further analysis.
“I would hope," Ackerman said, "the studies will be done well and produce facts that will be useful and they will be used to shape the future of the power sector in Oregon.”
In 40-plus years of studying energy issues, analysis always drove his decisions, agreed former PUC Chair Roy Hemmingway, who was energy advisor to three Oregon governors.
“I have not seen any technical analysis of this bill’s proposals, which represent the most significant changes in the state’s power system in 35 years,” Hemmingway said. “We have assertions from utilities and others but nothing to verify them.”
Human-caused climate change is the challenge of this era and renewables could be part of the solution but without analysis it is not possible to know how high a renewables penetration the system can handle, he said.
The bill will allow the electricity from the depreciated coal plants to be sold into other markets, Hemmingway added. “There are neighboring states where climate change is not a priority and they will be happy to buy the very cheap power.”
A carbon tax or cap and trade program would be better, he said. But while it is possible that the CPP will eventually impose a price on emissions, the judicial stay last month put that in doubt.
“The legislators have not had the time to understand the ramifications of the bill," Hemmingway said. "There is no question at all they would not take up something this complex and with this much uncertainty if it were not for the ballot initiative.”
Hemmingway does not accept claims from the bill's backers that rate impacts will be minimal.
“PGE says it expects the rate impact to be 1.5% annually," he said. "Compounded over the life of the bill, that is an over 40% rate increase, above all other rate increases. I don’t regard that is trivial.”
His estimate is the net cost per metric ton of emissions cuts will be over $350. “It would be far less expensive for Oregon to buy credits in carbon markets,” he said. "I would like nothing more than to see a public vetting of these and others’ numbers.”
The thing that is “amazingly missing” from the legislation is a requirement for utilities to shut down their out-of-state coal capacity, NARUC’s Kavulla said. “The conscience of Oregonians can be clear, but it's pretty clear that this bill won't actually reduce carbon emissions.”
Kavulla believes such policy changes should be made in partnership with regulators.
“The moment someone slaps a carbon price on the economy through a state policy or regulation we should incorporate it, and we should insist on a least-cost per ton approach,” Kavulla said. “Absent that, we should still be insisting on least-cost while incorporating the risk profile of these investments that go out 20, 30 years.”
Response to the critics
The 4% cap on the premium IOUs can pay for RPS compliant generation has and will continue to protect ratepayers, said Pacific Power's Schwark. “It is already a part of Oregon’s existing mandate and, to date, Pacific Power has not come close to it.”
Phasing out coal-generated electricity by 2030, under SB 1547 provisions, will have “no impact on customer rates through 2030,” according to Pacific Power’s analysis. There could be “an annual average cost increase of less than 1% between now and 2030.”
It will also save ratepayers “up to $600 million through 2030 versus the cost of the proposed ballot measure,” it found.
PGE has also not hit the 4% cap in the existing mandate, Robertson said. AndPGE’s estimate of SB 1547’s requirements shows it could result in a similar average annual price increase of only about 1.5% from 2017 to 2040.
It will also “put us on a trajectory to meet Oregon’s pretty aggressive carbon reduction rules of getting to 80% below 2005 levels by 2050,” Robertson added.
Another PGE analysis of cost impacts and dispatch across the West found that “when Oregon does these levels of new renewables, fossil plants across the West dispatch less,” Robertson said. “Coal and gas don’t get used as much. There is about a 30 million metric ton reduction of emissions. So the assertion that the bill will not reduce emissions is wrong.”
A Flink Energy study commissioned by Renewable Northwest, updated in February, concluded that the cost effects for the IOUs through 2040 “ranged from an average increase of 0.9% (no tax credits, no value on carbon) to a decrease of 2.8% (renewable energy tax credits, with high value on carbon). The calculated net costs include the effects of early depreciation of existing coal plants by the end of 2030.”
“It is accurate that this bill won’t close down any coal because the coal is outside Oregon,” said Renewable Northwest’s Gilmore. “But it will keep Oregon ratepayers from paying for coal-generated electricity.”
“It is not about what we can’t do to shut down coal plants,” Hojnowski agreed. “It is about what Oregon can do. It can say it won’t pay for coal-generated electricity anymore.”
There is not a lot of load in the Western grid outside California, Oregon, and Washington, Duncan observed.
“Those plants could re-dispatch if they can find a buyer," he said, "but as a practical matter, it won’t happen.”
Many of the plants are at least 40 years old and some are already planned for shuttering, he added. Assuming the CPP survives legal challenges, it will add pressure on them to shut down.
Consumer advocates and regulators need to begin thinking of coal as an economic risk, CUB’s Jenks said. The coal plants that now serve Oregon will need billions of dollars in regulation-imposed retrofits by 2030 so it would be expensive to continue relying on it.
“We have thought about renewables as a hedge against the volatility of natural gas price risk but coal may be the bigger economic risk because of all the other regulations coming down on it,” Jenks added. “We need to think about protecting ratepayers from that risk. That can bring utilities and environmental advocates together.”
The science of climate change is pretty undeniable and “a problem we need to fix,” said PGE’s Robertson. “A carbon tax might seem like a good idea to an activist or a policymaker but not to an electric utility because the ratepayer can’t see where that tax money goes. Give us the vision, and give us more leeway on the 'how,' and we will get there.”
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