New Law Gives Emergency Planners Oil By Rail Information
Monday, December 29, 2014, Amy Quinton / Capital Public Radio
Smoke rises from railway cars that were carrying crude oil after derailing in downtown Lac Megantic, Quebec, Canada, July 6, 2013. Credit: Associated Press
A new law that goes into effect Jan. 31 in California requires railroads to give more information to emergency planners about crude oil shipments.
Local and state emergency responders say they are given very little detail about the movement of trains carrying crude oil.
A 2013 Bakken crude oil train explosion that killed 47 people in Quebec raised awareness of the danger that poses.
Kelly Huston with the California Office of Emergency Services said with the predicted increase in the amount of imported crude oil, more information is needed.
“Being able to know what’s coming and then being able to prepare for it and take actions that may be needed whether it’s moving hazardous materials crews or whether it is, perhaps we know about an event that’s going on in a highly populated area and we would want to make sure the railroad is aware of that,” Huston said.
Under the new law, railroads will have to submit weekly schedules of trains, and the volumes of crude oil they carry. They would also have to set up a communications center for first responders and give local authorities access to emergency plans.
The California Energy Commission has estimated nearly a quarter of the oil imported into the state will be delivered by rail by 2016.
“It’s not only having the knowledge but also how we use that knowledge to both prevent an accident from occurring and then having adequate hazardous materials resources and first responder resources to respond in the event there is an accident,” Houston said.
Bakken outlook: Oil industry faces hurdles in 2015
By Mike Nowatzki, Dec 26, 2014
Brothers Dusty, left, and K.C. Sutton of Nine Energy Service prepare to install a blow out preventer on a new well on July 7 south of Stanley that has been fracked and needs to be cleaned out before it produces oil. FNS Photo by Michael Vosburg
BISMARCK — With oil prices slipping to their lowest point in more than five years, new state regulations slated to take effect and lawmakers proposing major investments in oil country, 2015 is shaping up to be a critical year for the oil and gas industry in North Dakota.
Here’s a look at some of the top issues.
New rules resonate
Rules adopted by the North Dakota Industrial Commission in 2014 will continue to resonate in 2015.
Gas capture goals adopted in July will require operators to reduce the percentage of natural gas flared from oil wells to 23 percent by Jan. 1 and to 15 percent by 2016.
Statewide, operators already met the first goal of 26 percent by Oct. 1, beating it by 4 percentage points.
But eight individual operators didn’t meet the gas capture goal, and several postponed completion work on wells to achieve the goal, Department of Mineral Resources Director Lynn Helms said.
North Dakota Petroleum Council President Ron Ness said substantial amounts of gas are being “held hostage” in negotiations over pipeline easements. He estimated well over one-third of the flared gas is the result of three or four easement hang-ups on private, tribal and federal lands.
“Those few bottlenecks are holding up a substantial amount of connections,” he said.
Oil conditioning required
Starting April 1, oil conditioning rules adopted by the Industrial Commission this month will require operators to use equipment to separate butane, propane and other volatile gases from crude oil, and to run the equipment within certain temperatures and pressures to lower the oil’s vapor pressure to 13.7 pounds per square inch.
State officials say the rules will improve the safety of crude-by-rail shipments. Critics contend they’ll do little to prevent the kind of explosive train derailments that spurred their creation.
Ness said the Petroleum Council was amenable to safety standards based on science but “we adamantly objected to the micromanagement” maintained in the final order. Some companies will have to make substantial investments in well-site equipment and testing required by the rules, he said, noting one operator believes their cost could range from $10 million to $20 million.
Requiring the equipment to be installed during the winter months so it’s ready by April 1 also was “a significant misstep,” he said.
“Operators are already in the process of figuring out what they need to do on each of their facilities to come into compliance, but I think we’re pretty frustrated with the process,” he said.
Price uncertainty high
Continued lower oil prices will make some drilling activity less profitable in emerging and mature oil plays, but prices are expected to remain high enough in 2015 to support new drilling in the major shale areas in North Dakota and Texas, the U.S. Energy Information Administration said in its short-term energy outlook Dec. 9.
The outlook forecasts average spot prices of $68 per barrel for Brent crude and $63 per barrel for West Texas Intermediate crude in 2015, with lower prices early in the year, the EIA said, citing “high uncertainty” in the price outlook.
Helms is optimistic prices will recover, calling the recent decline “a blip.”
Ness said the industry doesn’t see it that way, noting most analysts are predicting the price slump could last eight to 16 months or even one to two years as U.S. supply stays strong, global demand remains weak and OPEC continues to challenge U.S. production.
“We don’t know what the new normal for oil prices is going to be,” he said. “We’re in an energy war.”
North Dakota light sweet crude oil has dropped below $40 a barrel.
And while some barrels are hedged, “by and large, we’re probably taking $60 less a barrel than we were six months ago,” Ness said.
As a result, companies will deploy less capital and idle drilling rigs or move them from fringe areas to higher-producing areas, he said.
If low prices continue into February and March, “We’re going to see substantial reduction in exploration activity,” he said.
Helms said falling oil prices, oil conditioning and flaring reduction were factors in North Dakota’s drilling rig count dropping by 10 to 183 as of Dec. 12. He expects a 40- to 50-rig reduction by mid-2015 because of soft oil prices.
Oil tax reform?
Efforts to change North Dakota’s oil tax structure failed during the 2013 legislative session, and it remains to be seen whether similar proposals will surface when the Legislature convenes Jan. 6.
Sen. Dwight Cook, R-Mandan, chairman of the Senate Finance and Taxation Committee, introduced a bill last session that would have ended a series of 10 tax incentives designed to help draw oil companies to the state and keep them viable, while lowering the oil extraction tax from 6.5 percent to 4.5 percent for wells built after 2017. The bill failed in the House, as did an oil tax reform bill sponsored by Rep. Roscoe Streyle, R-Minot.
“I will not be introducing any similar legislation this session, and I haven’t heard of anybody else who has,” Cook said Tuesday. “But I guess I wouldn’t be surprised to see something.”
Trying to get rid of incentives – including reductions and exemptions to the extraction tax that take effect when the price of crude drops below a “trigger price” for five consecutive months – could be a tough sell with oil prices as low as they are, Cook said.
“You need to do that when there are high prices,” he said.
Ness said the Petroleum Council doesn’t plan to push any oil tax reform legislation.
“We fully expect that we’re going to sit back and utilize those incentives if they come,” he said.
Legislative proposals
Elected leaders have unveiled big spending proposals to address infrastructure, housing and other needs in oil-impacted areas of western North Dakota.
Chief among them is Gov. Jack Dalrymple’s budget recommendation to increase the share of oil production tax revenue being sent back to oil producing counties from 25 percent to 60 percent for the 2015-17 biennium, while lowering the state’s share from 75 percent to 40 percent. Senate Majority Leader Rich Wardner, R-Dickinson, is spearheading a similar proposal.
The adjusted formula would generate $1.7 billion for the counties and their political subdivisions, or $1 billion more than what the region is expected to receive this biennium, Dalrymple has said.
The governor also wants lawmakers to fast-track $873 million in “jump-start” funding so the state’s oil and gas region can get a head start on construction projects next spring. He’s also recommending $119 million in Energy Impact Grant funds.
Radioactive waste
Several illegal dumping incidents reported in 2014 focused attention on proper disposal of filter socks and other radioactive oilfield waste.
The North Dakota Department of Health has proposed rules that would increase the limit of radioactivity from 5 picocuries per gram to 50, allowing companies to dump the waste at special oilfield waste landfills and industrial waste landfills instead of having to haul it out of state. Companies also would be required to keep manifests to track the waste.
A public comment period is open until Jan. 31, and the approval process is expected to take several months. The Legislature’s Administrative Rules Committee must approve the rules.
“That’s going to get a lot of discussion,” Cook said.
Repost from The Sacramento Bee [Editor: Significant quotes: “…UP said new shipments into California from Canada started in late November, running through Idaho, Washington and Oregon…. The trains from Canada likely carry tar sands…. the trains from Canada appear to be traveling on the UP line that runs parallel to Interstate 5 through Northern California, which almost certainly takes them on one of several rail lines through Sacramento…. The new shipments are the first “unit” – or all-oil – trains to enter the Western U.S. from Canada, according to a report in Railway Age. Crude from Canada has been coming into California sporadically and in smaller shipments for more than a year, Railway Age reported.” See also Railway Age, UP begins Canada-to-California CBR service. – RS]
New crude oil trains from Canada arrive in California
By Tony Bizjak, 12/08/2014
In a sign that crude oil train shipments to California refineries are on the rise, Union Pacific railroad officials confirmed last week they are now transporting full trains of Canadian oil through Northern California on a route that likely cuts through central Sacramento.
State rail-safety inspectors shadowed the initial trains outside of Bakersfield and reported the mile-long trains were traveling at slow speeds, most likely out of caution, just days after a UP corn train derailed in the Feather River Canyon and spilled feed into the river.
The Canadian imports are the second set of all-oil trains now believed to be coming through the capital on a regular basis. A Bakken oil train comes through midtown Sacramento once or twice a week en route to Richmond in the Bay Area.
Several more oil trains may join them in the next year. Valero Refining Co. has applied for permission to run two 50-car oil trains a day through Sacramento to its plant in Benicia, and Phillips 66 has plans to run oil trains five days a week into its refinery in San Luis Obispo County, some from the north and some via southern routes.
State officials say the Canadian trains are heading to a newly opened transfer station outside Bakersfield, where the crude oil is expected to be piped to coastal refineries. The station, operated by Plains All American Pipeline, a Texas company, is the first of several crude-by-rail facilities planned for California in the next few years. Combined, they would give oil companies the ability to receive up to 22 percent of the state’s imported crude oil by rail instead of by marine shipment.
The increase nationally in train transport of North American crude has helped push international oil prices down dramatically in recent months. It also has raised concerns about the risk of derailments and oil spills. Sacramento officials have called on oil and rail companies and federal regulators to increase safety measures to protect against spills, including requiring stronger tank cars.
Citing safety issues of their own, rail companies have generally declined to disclose where and when rail shipments are happening. But in an email to The Sacramento Bee last week, UP said new shipments into California from Canada started in late November, running through Idaho, Washington and Oregon.
“We expect to run crude trains on this route moving forward,” UP’s Aaron Hunt wrote.
The trains from Canada likely carry tar sands, also called bitumen, which is considered less flammable than the Bakken oil from North Dakota. Bakken oil has been involved in a several major rail explosions in the last few years, including one that killed 47 people in a Canadian town. State safety officials say tar sands, viscous and heavy, are a threat to waterways because the material can sink, making spills hard to clean. A bitumen spill from a ruptured pipe forced closure of 35 miles of the Kalamazoo River in Michigan in 2010 and required $1 billion in cleanup costs over a three-year period.
The state recently called on railroads to provide plans that show that they have the wherewithal to clean oil spills on state waterways. Officials with the state Office of Spill Prevention and Response say tar sands may require particular equipment. “Businesses that transport heavy oils are required to have response resources necessary to address these types of spills,” state spokesman Steve Gonzalez said in an email. “Contractors must be able to locate, contain and clean up a spill that has sunk to the bottom of the water. Some of these responses include sonar, containment boom, dredges and pumps.”
Rail shippers point out that derailment numbers overall have been decreasing nationally for decades and that the industry now runs oil trains at slower speeds at times.
State Public Utilities Commission officials say they sent inspectors out near Bakersfield to monitor the first Canadian oil train, and another train headed to Bakersfield from the south, and noted that the trains were traveling slower than normal.
“The first run is a critical run. If anything goes wrong, we want to be there,” PUC rail safety chief Paul King said. “There might be compliance issues. We want to see how it interfaces with traffic, what speeds they decided to go.”
King said the trains from Canada appear to be traveling on the UP line that runs parallel to Interstate 5 through Northern California, which almost certainly takes them on one of several rail lines through Sacramento. Rail officials have declined to say which lines the oil trains use.
In May, the U.S. Department of Transportation required railroads to notify state officials of large shipments of Bakken oil. Many states ultimately made the information available through public records requests, against the wishes of the railroads. However, railroads are not required to report oil shipments from Canada or other non-Bakken domestic sources.
The new shipments are the first “unit” – or all-oil – trains to enter the Western U.S. from Canada, according to a report in Railway Age. Crude from Canada has been coming into California sporadically and in smaller shipments for more than a year, Railway Age reported.
Repost from The Benicia Herald [Editor: The Benicia Herald is one of very few news outlets to cover the Bay Area Air Quality Management District’s far-reaching and highly significant December 17 initiative on refinery emissions. The first Herald article just covered the facts, and oddly, is not posted on the Herald’s website. As a follow-up to that story, our local newspaper either sought out comments from the Refinery or responded to Valero’s overture, not sure which. Either way, we were treated on Christmas Eve to a front page Valero Benicia promotion of its wondrous efforts to control its emissions, and the supposedly small part Bay Area refineries play in contributing to greenhouse gases. Note especially Valero’s resolve to “participate in any new rulemaking to ensure rules are reasonable and cost effective.” Reasonable rules would surely protect community health and safety, no? And according to whose costs should regulatory effectiveness be weighed? For other reports on the Air District initiative, see The Contra Costa Times, and the Oil & Gas Journal. See also primary documents: BAAQMD 12/17 agenda, (p. 73), and REPORT: Bay Area Refinery Emissions Reduction Strategy (PDF) . – RS]
Emissions plan draws response from Valero
Refinery official: ‘Proud’ to contribute to better air quality
By Donna Beth Weilenman, December 24, 2014
The Bay Area Air Quality Management District is hoping its new five-component strategy will reduce emissions from refineries in it geographic area.
The district’s Refinery Emissions Reduction Resolution, approved Oct. 15, sets a goal of 20-percent reduction in refinery emissions — or as much as is feasible — during the next five years.
The Bay Area Air Quality Management District is the regional agency responsible for protecting air quality in the nine-county Bay Area.
The announced strategy would show the Air District how to achieve that goal.
“Our new Refinery Emissions Reduction Strategy continues and reaffirms the air district’s commitment to significantly decrease harmful air pollution in our communities,” said Jack Broadbent, the district’s executive officer.
“This strategy will ensure that refineries are taking the strongest steps to cut emissions and minimize their health impacts on neighboring residents and the region as a whole.”
But refineries are just one industry that contributes to the San Francisco Bay Area’s air pollution and greenhouse gas emissions, according to an official at Valero Benicia Refinery.
“By the district’s own data, Bay Area refineries make up only a small segment of overall emissions in the Bay Area air shed,” said Chris Howe, the refinery’s director of health, safety, environment and government affairs.
“These emissions have continued to decline over the last two decades,” Howe said, data which the Air District also acknowledged.
“We are proud of the significant contributions our refinery has made and will continue to make to improve air quality, especially with the installation of our flue gas scrubber in 2011,” Howe said, citing a major component of the Valero Improvement Project.
In addition, he said, “We will continue to participate in any new rulemaking to ensure rules are reasonable and cost effective when weighed against the many options the district has to regulate emissions in our air basin.”
Broadbent said the Air District’s announced strategy sets overall goals of a 20-percent reduction in both criteria pollutants from refineries and in health risks to area communities, both within the next five years. That is the strategy’s first component.
To do this, the Air District plans to investigate significant sources of those pollutants at the refineries themselves, and to examine a variety of additional pollution controls at those sources, he said. That’s the second component.
He said this would be done under the district’s focused Best Available Retrofit Control Technology program.
“Rulemaking is already under way to reduce sulfur dioxide from coke calciners and particulate matter from catalytic cracking units,” Broadbent said.
“Several other rules to reduce refinery emissions will be developed in 2015.”
The strategy’s third component would be the Air District’s approach to reduce health risks from toxic air pollution, Broadbent said.
He said it would begin with requirements to reduce toxic emissions from such refinery sources as cooling towers and coking units.
Site-wide health risks would be assessed, and sources for further emissions controls would be identified, with an eye toward health benefits, he said.
A fourth component would be evaluation of greenhouse gas emissions at the refineries and their reductions as a result of the cap-and-trade system put in place under Assembly Bill 32.
That bill, signed into law Sept. 27, 2006, requires the California Air Resources Board (CARB) to develop regulations and market mechanisms to reduce California’s greenhouse gas emissions to 1990 levels by the year 2020.
CARB adopted a cap-and-trade program Dec. 17, 2010, allowing some emitters to buy credits at quarterly auctions for additional emissions.
Under the Air District’s strategy, refinery performance would be compared to third-party standards for best practices, with analysis of potential further opportunities for reductions, Broadbent said.
The fifth component concerns continuous improvement in emission reductions, for which refinery operators would be required on a periodic basis to evaluate the sources of most of their emissions to determine if more controls are needed.
Broadbent said the Air District would develop its package of rules in the coming year, and would be working with members of the public as well as refinery industry representatives to make any modifications in the proposed rules and to use the strategy to reach those stated goals.
In addition, the Air District will prepare its Petroleum Refining Emissions Tracking rule that requires updated health risk assessments, additional fence-line and neighborhood monitoring capacity and the compiling of an annual emissions inventory.
Simultaneously, the Air District will write a companion rule to set emissions thresholds and mitigate potential increases at refineries, Broadbent said.
Those rules are expected to be sent to the Air District’s board for adoption in 2015.
The San Francisco Bay Area’s five major oil refineries, including Valero Benicia Refinery, produce air pollution and greenhouse gases in the region, Broadbent said, and “these are already subject to more than 20 specific Air District regulations and programs, and their overall emissions have been steadily decreasing.”
