Governor joins environmental community, energy industry to highlight new rules for oil and gas activities

February 26, 2014
Wattenberg Oil and Gas Field via Free Range Longmont

Wattenberg Oil and Gas Field via Free Range Longmont

Here’s the release from Governor Hickenlooper’s office:

Gov. John Hickenlooper was joined today by representatives from the environmental community, the energy industry and state agencies to discuss the Colorado Air Quality Control Commission’s recent approval of comprehensive changes to rules governing oil and gas activities in the state.

The new rules include the nation’s first-ever regulations designed to detect and reduce methane emissions.

“All Coloradans deserve a healthy economy and a healthy environment, and we’ve taken yet another critical move to help make sure that Colorado will continue to have both. The new rules approved by Colorado’s Air Quality Control Commission, after taking input from varied and often conflicting interests, will ensure Colorado has the cleanest and safest oil and gas industry in the country and help preserve jobs,” Hickenlooper said. “We want to thank the environmental community, the energy industry and our state agencies for working together so hard to take this significant step forward.

“We’re fortunate to live in this beautiful, vibrant state. We enjoy it every day, and we don’t for one second take it for granted. It’s collaborative efforts like this, the result of everyone working together, that will help ensure Colorado’s tomorrow is even brighter than today.”

Representatives from the environmental community, the energy industry and state agencies at the press conference today included: Fred Krupp from the Environmental Defense Fund; Pete Maysmith from Conservation Colorado; Ted Brown from Noble Energy; Craig Walters from Anadarko; Angie Binder from Encana; Dr. Larry Wolk from the Colorado Department of Public Health and Environment (CDPHE); and Gerald Nelson, an economist from Grand Junction.

The new Oil and Gas Emission Rules were adopted by the Colorado Air Quality Control Commission on Sunday, Feb. 23, 2014. The regulations resulted from the governor’s calls for further action to minimize potential negative air quality impacts associated with oil and gas development.

The rules continue Colorado’s leadership in ensuring responsible development under the most stringent and protective standards in the country. A coalition of environmental and industry interests worked with the administration on the rules. Highlights of the rules include:

  • The most comprehensive leak detection and repair program for oil and gas facilities in the country.
  • Regulation of a range of hydrocarbon emissions that can contribute to harmful ozone formation as well as climate change. The rules include first-in-the-nation provisions to reduce methane emissions.
  • Implementation of the rules will reduce more than 92,000 tons per year of volatile organic compound emissions. VOC emissions contribute to ground level ozone that has adverse impacts upon public health and environment, including increased asthma and other respiratory ailments.
  • Implementation of the rules also will reduce of more than 60,000 tons per year of methane emissions. As a natural gas, methane provides a clean and affordable domestic energy source. But when it leaks or vents to the atmosphere, it is a potent greenhouse gas.
  • Expanded control and inspection requirements for storage, including a first-in-the-nation standard to ensure emissions from tanks are captured and routed to the required control devices.
  • Expands ozone non-attainment area requirements for auto-igniters and low bleed pneumatics to the rest of the state
  • Require no-bleed (zero emission) pneumatics where electricity is available (in lieu of using gas to actuate pneumatic)
  • Require gas stream at well production facilities either be connected to a pipeline or routed to a control device from the date of first production.
  • Require more stringent control requirements for glycol dehydrators.
  • Require use of best management practices to minimize the need for – and emissions from – well maintenance.
  • Many operators will use infrared (IR) cameras, which allow people to see emissions that otherwise would be invisible to the naked eye. Colorado obtained IR cameras for CDPHE and the Department of Natural Resources inspectors last year. They are an effective tool in identifying leaking equipment and reducing pollution.
  • Comprehensive recordkeeping and reporting requirements to help ensure transparent and accurate information.
  • Adoption of federal oil and gas standards that complement the state-specific rules.
  • The unofficial draft of the rules now will be sent to the Colorado Secretary of State’s Office for publication, prior to the rules becoming effective in the spring. Click on the highlighted “Regulations 3, 6 & 7” to view the complete regulations.

    From the Denver Business Journal (Cathy Proctor):

    Gov. John Hickenlooper knows that Colorado’s new air quality rules for oil and gas operations, lauded as the strictest in the nation, won’t please everyone…

    At a press conference Tuesday at the state Capitol, Hickenlooper said Colorado’s new air quality rules were the result of the collaborative efforts of some of the state’s biggest oil and gas companies, a national environmental group and state regulators. But he said he knows that others want more.

    “There’s a group that wants to ban hydrocarbons, to ban hydraulic fracturing, and today’s not going to satisfy people who are against all hydrocarbons and want to have all renewable fuels,” Hickenlooper said. “Natural gas will be a transition fuel, and our efforts today are focused on how we do that as cleanly as possible.”[...]

    State officials have pegged compliance costs at about $42.5 million a year, or less than $500 per ton of pollution eliminated.

    Executives at some of Colorado’s biggest oil and gas companies have said the state’s estimate is in line with their estimates and a cost they consider acceptable.

    Here’s a release from Earth Justice (Michael Freeman):

    Today, Governor Hickenlooper held a press conference to celebrate the Colorado’s Air Quality Control Commission’s adoption of groundbreaking revisions to rules that govern the oil and gas industry. The new rules include measures to help protect Coloradans from air pollution caused by the industry’s fracking-fueled boom and make Colorado the first state in the nation to regulate emissions of methane—a powerful greenhouse gas—from the oil and gas industry.
    The Commission’s resounding 8–1 vote came Sunday after a contentious five-day hearing in which powerful industry trade associations opposed the Governor’s proposed revisions. In the end, the Commission stood with Coloradans from across the state who spoke out in favor of accepting and strengthening the Governor’s proposal.

    Earthjustice Rocky Mountain Office staff attorneys Michael Freeman and Robin Cooley represented a coalition of conservation groups—the Sierra Club, Natural Resources Defense Council, WildEarth Guardians and Earthworks Oil and Gas Accountability Project—in the just completed rulemaking process.

    Following the Governor’s press conference, Michael Freeman stated: “Today, we join many other Coloradans in celebrating the new rules. While these rules won’t be enough to bring Colorado into compliance with federal air quality standards, they’re a good first step. We look forward to finishing the job and ensuring that all Coloradans can breathe clean air.”

    Robin Cooley added: “Getting a handle on methane emissions from the fracking industry will be necessary for the United States to address climate change. These rules make Colorado a leader in that effort.”

    From the Denver Business Journal (Cathy Proctor):

    Colorado’s new air quality regulations for oil and gas operations are the strictest in the nation, says Fred Krupp, the president of the Environmental Defense Fund, which participated in meetings that led to the proposed rules…

    “There is more work to be done of course — whether it is addressing carbon pollution from power plants or making sure we are using energy as efficiently as possible. But let’s take a moment today to say, “job well done.” If we can replicate the cooperation and collaboration represented here today – we can provide a cleaner, safer environment for our children and grandchildren. — Pete Maysmith, executive director Conservation Colorado.

    More oil and gas coverage here and here.


    Snowpack news: Reclamation’s current forecast for Fry-Ark deliveries = 63,000 acre-feet #ColoradoRiver

    February 23, 2014

    From The Pueblo Chieftain (Chris Woodka):

    The Bureau of Reclamation has estimated a banner year for Fryingpan-Arkansas flows — with a disclaimer.

    “The forecast is based on average conditions for the rest of the spring,” said Roy Vaughan, Reclamation’s manager for the Fry-Ark Project. “We’ve seen it continue to snow and rain, and we’ve seen everything stop in March.”

    Vaughan spoke at Wednesday’s meeting of the Lower Arkansas Valley Water Conservancy District.

    Based on snowpack of 140 percent of median in the Fry-Ark collection area on the other side of the Continental Divide on Feb. 1, Reclamation predicts 63,800 acre-feet of water could be imported this year. If it holds, that would be about 20 percent higher than normal. But that number could be influenced by when and how quickly the snow melts in May and June. It also depends on whether snows continue during March and April, when the mountains typically get the largest accumulation of snow.

    While the Arkansas River basin is reporting storage levels of 64 percent of average, Fry-Ark reservoirs are 85-105 percent of average for this time of year, Vaughan said. Turquoise Reservoir, near Leadville, is at 105 percent, while Twin Lakes and Pueblo are about 85 percent of average.

    Reclamation wants to move about 30,000 acre-feet of water out of Turquoise Lake, but can’t because it is making repairs on the turbines at the Mount Elbert hydroelectric plant. Most of the water moved between Turquoise and Twin Lakes goes through a large tunnel that feeds the Mount Elbert forebay. Repairs should be completed in early March, Vaughan said.

    The Southeastern Colorado Water Conservancy District will allocate water from the Fry-Ark Project in May. About 53 percent goes to cities and 47 percent to farms under the district’s allocation principles.

    From the USDA:

    Limited water supplies are predicted in many areas west of the Continental Divide, according to this year’s second forecast by the National Water and Climate Center of USDA’s Natural Resources Conservation Service (NRCS).

    Right now, snow measuring stations in California, Nevada and Oregon that currently don’t have any snow, and a full recovery isn’t likely, the center’s staff said.

    USDA is partnering with states, including those in the West, to help mitigate the severe effects of drought on agriculture.

    USDA announced last week that $15 million was available for conservation assistance to farmers and ranchers in affected areas in California, Texas, Oklahoma, Nebraska, Colorado and New Mexico. As part of the announcement, $5 million was also made available to California communities through the Emergency Watershed Protection Program. Earlier this month, USDA made another $20 million available to farmers and ranchers in California. Agriculture Secretary Vilsack joined President Obama in California on February 14th to announce those and other drought relief measures.

    Parts of eastern California are now in a state of emergency because of drought. This area is suffering one of the lowest snow years on record. Meanwhile, in Oregon, mountain snowpack is far below normal.

    “The chances of making up this deficit are so small that at this point we’re just hoping for a mediocre snowpack,” said NRCS Hydrologist Melissa Webb for Oregon. “We’d need months of record-breaking storms to return to normal. There’s a strong chance we’ll have water supply shortages across most of Oregon this summer.”

    Most Oregonians don’t have access to water from other states and depend on local sources for water supply.

    Across the Continental Divide, Montana, Wyoming and Colorado are mostly near normal. The one exception is New Mexico, which is extremely dry.

    Although NRCS’ streamflow forecasts do not predict drought, they provide information about future water supply in states where snowmelt accounts for the majority of seasonal runoff.

    NRCS has conducted snow surveys and issued regular water supply forecasts since 1935 and operates SNOTEL, a high-elevation automated system that collects snowpack and related climatic data in the western United States and Alaska. These data help farmers, ranchers, water managers, hydroelectric companies, communities and recreational users make informed, science-based decisions about future water availability.

    View February’s Snow Survey Water Supply Forecasts map or view information by state.


    Hydraulic fracturing: ‘It really is just water and sands that goes down a hole’ — William Fronczak

    February 22, 2014

    The hydraulic fracturing water cycle via Western Resource Advocates

    The hydraulic fracturing water cycle via Western Resource Advocates


    From The Fort Morgan Times (Rachel Alexander):

    He said the fluid used in the hydraulic fracking, as it is called, process is 99 percent water and sand, with only a small percentage being added chemicals.

    “It really is just water and sands that goes down a hole,” Fronczak said.

    He said vertical fracking uses between 375,000 and 410,000 gallons of water while the more frequently used horizontal fracking uses between 2 and 4 million gallons.

    “There’s a lot of logistics handling water,” he said. “We don’t want to shut down a frack due to water.”

    Fronczak used a variety of charts to show the association members how the actual fracking is only a small portion of what is done with the industry’s water. Initially, water has to be sourced, then transported or transferred to the fracking site. After it is brought out of the fracking hole, the water has to be contained and treated.

    “The challenge is meeting that high rate of demand in a short period of time,” Fronczak said.

    He discussed the limitations of trucking water to fracking sites and the use of piping to transfer the water over distances. This also allows the industry to decrease its carbon footprint.

    “Where there’s a lot of activity, there’s not a lot water,” he said, adding that industry members have work to find solutions to the water issue. “Closest water isn’t always the best. From a quality standpoint as well as from a logistical standpoint.”

    More oil and gas coverage here and here.


    COGCC flood response lessons learned forum recap

    February 7, 2014
    Flooded well site September 2013 -- Denver Post

    Flooded well site September 2013 — Denver Post

    From the Fort Collins Coloradoan (Ryan Maye Handy):

    Colorado oil and gas regulators set a precedent on Thursday by hosting a public forum on lessons learned from oil spills caused by the September 2013 floods, said Colorado Oil and Gas Conservation Commission Director Matt Lepore.

    But in recapping its response to the spills — which poured about 43,000 gallons of oil into the South Platte River basin — few new updates came out of the meeting, held in the Wells Fargo building in downtown Denver. Representatives from COGCC, a state agency that regulates oil and gas, and industry advocacy group the Colorado Oil and Gas Association, spoke about response to the spills that alarmed Front Range residents for weeks last fall. The groups intend to present a series of recommendations to the state government as a result of their review, Lepore said.

    But the main purpose of the meeting — time for public discussion — was largely a bust. Lepore had set aside an hour for discussion with an audience of more than 70 people, but after four or five comments and questions, the audience was silent.

    “I am pleased with the turnout,” Lepore said after the meeting adjourned almost an hour early. “Honestly, I hoped for much more dialogue.”[...]

    When it comes to flood aftermath, Laura Belanger, an environmental engineer with Western Resource Advocates, is still hopeful that COGCC’s list of best management practices — now only suggestions — become hard-and-fast rules. While larger oil and gas operators might go above and beyond what the list recommends, smaller operations may not, she said.

    More oil and gas coverage here and here.


    The COGCC explores expanded policy for horizontal drilling ‘communication’ with existing wells

    February 6, 2014
    Potential vertical and horizontal drilling conflict via The Grand Junction Daily Sentinel (Robert Garcia)

    Potential vertical and horizontal drilling conflict via The Grand Junction Daily Sentinel (Robert Garcia)

    From The Grand Junction Daily Sentinel (Dennis Webb):

    The Colorado Oil and Gas Conservation Commission plans to expand statewide a policy aimed at preventing horizontal wells from causing leaks involving existing wells, due to a leak southwest of De Beque where such a possible link is being investigated.

    The Bureau of Land Management also is looking at what it can do to try to help head off such problems.

    The agencies’ actions follow the Dec. 14 discovery of natural gas and fluids bubbling up around a Maralex Resources well on Jaw Ridge, which is BLM-managed land about seven miles from De Beque. The leak’s cause continues to be investigated, and one possibility the COGCC is considering is that it resulted from hydraulic fracturing of a Black Hills Exploration & Production well that was drilled from a surface site about a mile away, but made a 90-degree turn underground and passed within about 400 feet of the Maralex well.

    The Maralex well was drilled in 1981 but was shut in shortly after its drilling. It stopped leaking Jan. 17, as work continued on permanently plugging it, an effort completed a week later. Fluids initially escaped from the well pad after the leak’s start. Maralex then opened the well and directed the flow into a pit for removal by truck. That flow fluctuated widely but averaged about 6,300 gallons a day during the month before it ceased. Authorities have found no indication of contamination of surface water or groundwater. Testing continues to try to determine exactly how far the fluids spread beyond the pad within what the BLM considers to be a known maximum spill parameter.

    ‘COMMUNICATION’ CONCERN

    The COGCC currently has a policy aimed at preventing what it calls the potential for “communication” between horizontal wells and existing wells in 11 counties in eastern Colorado’s Denver-Julesburg Basin. That area is seeing a boom in horizontal drilling aimed at producing oil and other liquids, in an area with numerous existing vertical wells that in some cases may not have been constructed to withstand modern-day, high-pressure fracture operations nearby.

    “It is apparent that that policy needs to be pushed out statewide. It needs to be pushed out statewide very quickly,” COGCC director Matt Lepore told the commission at its last meeting.

    The policy requires the COGCC engineer to evaluate all wells within 1,500 feet of a proposed horizontal wellbore to determine whether the existing wells have adequate cement sealing around them to isolate the geological formation to be fractured, as well as all groundwater zones. Also to be evaluated is whether an existing well’s wellhead and master valve are rated to 5,000 pounds per square inch of pressure, or alternatively that there is adequate mechanical isolation down the well.

    If concerns exist regarding an existing well, the company proposing the horizontal well must take measures that can range from doing remedial cement work in the existing well to isolate all formations, to properly plugging it, to replugging it if needed or proposing alternative mitigation. An existing well’s owner cannot refuse to let mitigation work occur.

    The COGCC initially implemented the policy for horizontal wells coming within 300 feet of existing wells. It eventually expanded the distance after pressure readings and other data collected at existing wells during fracking of new ones indicated a need to do so.

    Lepore told the commission one concern companies have is the lack of data that would justify the 1,500-foot-distance standard in the case of wells outside the DJ Basin. He also noted that there are currently few plans to drill horizontal wells elsewhere in the state. Companies have been drilling a small number of such wells for exploratory purposes in the Piceance Basin.

    LEAK THEORY INVESTIGATED

    The Maralex well was drilled into the Dakota sandstone formation, while the Black Hills well targeted the Niobrara shale, part of the shallower Mancos formation. The COGCC says the Maralex well wasn’t cemented to isolate the Niobrara zone because that zone wasn’t considered a producing formation when the well was drilled. It’s looking at whether gas liberated from fracking the Black Hills well reached the Maralex well, pushing gas and water to the surface.

    Bruce Baizel, energy program director with the Earthworks conservation group, has said another concern in horizontal drilling is that it may occur around older existing wells that may have corroded pipes or cement sealing that has weakened over time and can’t stand up to fracking pressures.

    Maralex plugged its well in stages after the discovery of the leak. When it finished plugging the Dakota sandstone formation, the leak slowed but continued. The leak stopped once plugging was completed at the top of the Mancos formation. But that in itself hasn’t been enough to convince officials that the Black Hills well fracking caused or contributed to the problem.

    Test results of fluid that flowed back from the Black Hills well are still being awaited. Samples of flowback fluid from another Black Hills horizontal well farther from the Maralex well proved to differ significantly from the fluid that came up the Maralex well.

    THE BLM’S ROLE

    Agency spokesman Steven Hall called the Maralex situation a rare one for the BLM, which he believes has seen few instances where fracking has occurred close to shut-in wells on lands it administers in Colorado. While noting that the leak’s cause hasn’t been determined, he said the BLM wants to do what it can to prevent problems between horizontal and existing wells. He said the BLM is reviewing how it manages horizontal drilling and fracking on federal land in the state. The agency has no rules or policies addressing potential communication between horizontal and existing wells. But Hall said it has a lot of leeway during the process of reviewing drilling permit applications to impose conditions to try to avoid such situations. In addition, it is working to deal with the situation of wells that are shut in for a long time, to make sure they are permanently plugged, put into production, or tested to ensure their integrity.

    “We’re going to try to be very aggressive in addressing those,” Hall said.

    The agency previously has said that of 110 wells Maralex owns that involve federal lands or minerals in western Colorado, 86 are shut-in — in nearly half those cases for more than 20 years. It has met with Maralex about coming up with a strategy for addressing its shut-in wells.

    More oil and gas coverage here and here.


    New Hydraulic Fracturing Report Finds Texas and Colorado Face Biggest Water Sourcing Risks

    February 6, 2014
    The hydraulic fracturing water cycle via Western Resource Advocates

    The hydraulic fracturing water cycle via Western Resource Advocates

    Here’s the release from CERES via CSRWire:

    As hydraulic fracturing is increasingly used for oil and gas extraction across much of the United States and Western Canada, a new Ceres report issued today shows that much of this activity is happening in arid, water stressed regions, creating significant long-term water sourcing risks for companies operating in these regions as well as their investors.

    The report provides first-ever data on oil & gas companies’ water use and exposure to the most water stressed regions, including those in Texas, Colorado and California. It includes recommendations for companies to improve their water management and reduce their overall exposure to water sourcing risks.

    “Hydraulic fracturing is increasing competitive pressures for water in some of the country’s most water-stressed and drought-ridden regions,” said Ceres President Mindy Lubber, in announcing Hydraulic Fracturing and Water Stress: Water Demand by the Numbers. “Barring stiffer water-use regulations and improved on-the-ground practices, the industry’s water needs in many regions are on a collision course with other water users, especially agriculture and municipal water use. Investors and banks providing capital for hydraulic fracturing should be recognizing these water sourcing risks and pressing oil and gas companies on their strategies for dealing with them.”

    The report is based on water use data from 39,294 oil and gas wells reported to FracFocus.org from January 2011 through May 2013 and water stress indicator maps developed by the World Resources Institute (WRI). It shows that nearly half of the wells were in regions with high or extremely high water stress. (Extreme high water stress regions, as defined by WRI, are areas where 80 percent of available surface and groundwater are already allocated to municipal, industrial and agricultural users.) Read the rest of this entry »


    Noble Energy looks to the Denver Basin Aquifer System for non-tributary groundwater for operations

    January 29, 2014
    Denver Basin Aquifers confining unit sands and springs via the USGS

    Denver Basin Aquifers confining unit sands and springs via the USGS

    From The Greeley Tribune (Eric Brown):

    Many water needs in the region have been met by buying supplies from farmers and ranchers, but a Noble Energy manager said Tuesday the oil and gas industry could and should stop being a part of that problem, and explained what his company is doing to get water. The large energy developer is looking to use deep groundwater wells — drawing “non-tributary water” — to meets its needs down the road, said Ken Knox, senior adviser and water resources manager for Noble, during his presentation at the Colorado Farm Show in Greeley.

    Farmers and others who pump groundwater typically draw water that’s less than 100 feet below the Earth’s surface — water that’s considered to be “tributary,” because it’s connected to the watershed on the surface and over time flows underground into nearby rivers and streams, where it’s used by farmers, cities and others. Wanting to avoid water that’s needed by other users, Knox said Noble is looking to have in place about a handful of deep, non-tributary groundwater wells that draw from about 800 to 1,600 feet below the Earth’s surface. Digging wells that deep is considered too expensive for farmers, Knox and others said Tuesday, and the quality of water at that depth is typically unusable for municipal or agricultural uses.

    One of Noble’s deep groundwater wells is already in place, and the company is currently going through water court to get another four operating in the region down the road, Knox said. Along with digging deeper for water, Knox explained that Noble across the board is “strategically looking” to develop water supplies that don’t put them in competition with agriculture or cities.

    Oil and gas development, according to the Colorado Division of Natural Resources, only used about 0.11 percent of the state’s water in 2012 — very little compared to agriculture, which uses about 85 percent of the state’s supplies. But in places like Weld County — where about 80 percent of the state’s oil and gas production is taking place, and where about 25 percent of the state’s agriculture production is going on, and where the population has doubled since 1990 and is expected to continue growing — finding ways for an economy-boosting energy industry to not interfere with the water demands of farmers, ranchers and cities is critical.

    The growing water demands of the region is coupled with the fact that the cheapest way to build water supplies is to purchase them from farmers and ranchers who are leaving the land and willing to sell. Those factors leave the South Platte Basin, which covers most of northeast Colorado, potentially having as many as 267,000 acres of irrigated farmland dry up by 2050, according to the Statewide Water Supply Initiative Study, released by the state in 2010.

    With that in mind, the Colorado Farm Show offered its “Water Resources Panel: Agriculture, Urban and Oil and Development Interactions.”

    Joining Knox on the panel were John Stulp, who is special policy adviser on water to Gov. John Hickenlooper; Dave Nettles, division engineer with the Water Resources Division office in Greeley; and Jim Hall, resources manager for the city of Greeley. The panel was moderated by Reagan Waskom, director of the Colorado Water Institute at Colorado State University.

    Knox also spoke Tuesday of Noble’s and other energy companies’ efforts to recycle the water they use in drilling for oil and gas — a hydraulic fracturing process, or “fracking,” that involves blasting water, sand and chemicals into rock formations, about 7,000 feet into the ground, to free oil and natural gas. The average horizontal well uses about 2.8 million gallons of water. Some water initially flows out of the well, but another percentage flows back over time. Knox stressed it is cheaper for companies to dispose of that returned water and buy fresh water for drilling purposes than it is to build facilities that treat used water. But, seeing the need to make the most of water supplies in the region, Noble is willing to invest in water-recycling facilities and other water-efficiency endeavors.

    Hall noted that the city of Greeley, which leases water to both ag users and oil and gas users, has seen a decrease in the amount of water it leases for energy development. With improved technology and improved drilling techniques, also decreasing is the amount of land oil and gas development is using, and the number of water trucks on rural roads.

    Knox said oil and gas companies — once requiring about 8 acres for one well site — can now put four to eight wells on just 3 acres, meaning the impact on farm and ranch land is less than it once was. By becoming more water efficient, he said Noble has decreased its water truck loads by 1.65 million annually, and reduced its carbon dioxide emissions by 264,000 tons.

    More oil and gas coverage here and here.


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