Preview Newsletter
Contura - February 4, 2019
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Mining entities awarded for safety efforts
Feb 3, 2019 | The Register-Herald (WV)
By Matt Combs
Last week, at its annual West Virginia Mining Symposium, the West Virginia Coal Association recognized companies for their efforts in safety and in mine reclamation. -
Experts do not foresee coal M&A, capex in 2019; sector, banks wary of investment
Feb 1, 2019 | S&P Global Market Intelligence (Online)
By Ellie Potter
While U.S. coal producers are hesitant to invest in new capacity at the moment, several industry professionals said at a recent energy event that they do not foresee widespread consolidation any time soon. -
Ohio warns potential buyer of certain Westmoreland coal assets may be blocked
Feb 1, 2019 | S&P Global Market Intelligence (Online)
By Taylor Kuykendall
Ohio environmental officials warned a bankruptcy court that the potential stalking horse buyers of certain Westmoreland Coal Co. assets may be prohibited from operating the purchased coal mines. -
Westmoreland moves to end coal contract with Colstrip
Feb 3, 2019 | Casper Star-Tribune (WY)
By Tom Lutey
Plans are in the works to end the supply contract between Colstrip power plant and the coal mine that’s kept it firing for more than 40 years. -
Powder River Basin coal production down in Q4'18, flat to year-ago period
Feb 4, 2019 | S&P Global Market Intelligence (Online)
By Taylor Kuykendall
Powder River Basin coal production fell from 86.6 million tons in the third quarter of 2018 to 83.9 million tons in the fourth quarter, a figure slightly higher than the fourth quarter of 2017. -
Cleanup of Montana Coal Train Derailment Could Take Weeks
Feb 1, 2019 | Associated Press (Online)
A Montana rail company official says it will likely take weeks to clean up a coal train derailment that happened this week east of Bozeman. Montana Rail Link spokesman Ross Lane tells the Bozeman Daily Chronicle that the company has started to remove coal, tainted soil and cars from the area near Rocky Creek where 39 rail cars derailed on Tuesday. -
Indiana Shipping Ports See Big Jump in Cargo Shipments
Feb 4, 2019 | Associated Press (Online)
Indiana's three major shipping ports handled a record amount of cargo last year as a big jump in coal shipments helped them see 25 percent growth from 2017. The Ports of Indiana agency says the two Ohio River ports at Mount Vernon and Jeffersonville and the Lake Michigan port at Burns Harbor handled 14.8 million tons of cargo last year. That's 21 percent more than the previous record in 2015. -
Sick and Struggling in Coal Country
Feb 4, 2019 | Associated Press (Online)
By Binghui Bang
The borough is in the heart of Pennsylvania's Coal Region, known for the richest deposits of anthracite in the country. The region is one of Pennsylvania's sickest, state statistics bear out, and rising health care costs make it hard for clinics and doctors to keep their doors open. Pennsylvania's rural residents are more likely to die from chronic illnesses, drug overdoses and suicides than people who live in many other parts of the state. -
MSHA looks to 'difficult solutions' to lower miner dust exposure, official says
Feb 3, 2019 | S&P Global Market Intelligence (Online)
By Taylor Kuykendall
Further reducing coal miners' exposure to dust, a cause of black lung disease, could require some tough solutions, a federal official told coal industry representatives in West Virginia. U.S. Mine Safety and Health Administration officials rolled out the final implementation of a lower respirable dust standard in August 2016 to the protest of some in the coal industry, including Murray Energy Corp., which sued the Obama administration over the new standard. The industry and its regulators have faced scrutiny from media reports about rising cases of black lung, a debilitating disease affecting coal miners. -
Lawmakers make new push for retired miners
| E&E News
By Dylan Brown
Lawmakers have renewed their bid to fix the United Mine Workers of America pension problem while also extending health care help to even more union miners as coal companies continue to go bankrupt. Rep. David McKinley (R-W.Va.) returned with the latest version of the "Miners Pension Protection Act" last week after a special joint congressional committee failed to reach a broader pension deal last year. -
Va. lawmakers reject plan to phase out fossil fuels
Feb 1, 2019 | S&P Global Market Intelligence
By Darren Sweeney
Virginia lawmakers shot down a plan to phase out the use of fossil fuels and transition the state to 100% clean energy. The Virginia House of Delegates voted 51-48 along party lines Jan. 31 to reject several amendments before ultimately voting 86-12 to reject House Bill 1635. -
Ala. utility plans to close coal-fired plant, citing US EPA coal ash rule
Feb 4, 2019 | S&P Global Market Intelligence (Online)
By Zack Hale
PowerSouth Energy Cooperative will retire its coal-fired Charles R. Lowman plant due to federal coal ash regulations, the utility's CEO said. The 556-MW plant's three units will be replaced with natural gas-fired generation, CEO Gary Smith told employees in a Dec. 31, 2018, message. Smith cited the U.S. Environmental Protection Agency's Coal Combustion Residuals, or CCR, rule as the driving force behind the move. -
5 years after Dan River coal ash spill, Duke Energy close to finishing state-mandated cleanup at site
Feb 2, 2019 | The Roanoke Times (VA)
By Jennifer Fernandez
Five years ago Saturday, a drainage pipe under a coal ash pond at the Dan River Steam Station near Eden ruptured, spilling up to 39,000 tons of the cloudy waste into the river. It marked the third-largest coal ash spill in U.S. history. -
Georgia Power plans to add 1,000 MW of renewable capacity, remove 5 coal units
Feb 2, 2019 | S&P Global Market Intelligence
By Darren Sweeney
Georgia Power Co. plans to add up to 1,000 MW of new renewable resources to its portfolio and shut down five coal units as part of its 20-year resource plan filed with state regulators. Georgia Power on Jan. 31 filed its 2019 integrated resource plan, or IRP, with the Georgia Public Service Commission -
Advocates see 'real opportunity' to cap carbon
| E&E News
By Benjamin Storrow
After toying with the idea for more than a decade, Oregon may finally be on the verge of putting in place a cap-and-trade system for carbon. Last week, lawmakers unveiled a bill several years in the making that calls for cutting emissions 45 percent of 1990 levels by 2035 and 80 percent by 2050. The measure would cap emissions beginning in 2021 and give utilities a decade before they have to buy carbon credits. It would also provide a declining number of allowances to trade-exposed industries. -
Deep freeze prompts Trump administration to re-up bid to bolster coal plants
Feb 2, 2019 | Washington Examiner (DC)
By Josh Siegel
The Trump administration is relitigating its arguments supporting coal after the fading fuel source was used more frequently this week to help meet surging power demand during the deep freeze that overtook the Midwest and East Coast. -
Opinion: America Should Better Utilize Advanced Coal
Feb 1, 2019 | Forbes
By Jude Clemente
Indeed, one of the great myths in our ongoing energy-environment discussion is that only renewable energy systems are evolving. The reality, of course, is that fossil fuel-based technologies are constantly improving as well. Our use of fossil fuels is always becoming more efficient with systems needing less fuel (feed) to generate more energy and becoming cleaner by emitting less greenhouse gases. -
India ramps up spending on coal exploration as it slashes funds for mine safety
Feb 1, 2019 | Reuters
By Sudarshan Varadhan
The Indian government will increase spending on exploration of coal and lignite by 20 percent in the coming financial year but will slash funding for coal mine safety and conservation, according to the federal budget document released on Friday. -
Opinion: South Africa will struggle to boost coal exports, even if it wants to: Russell
Feb 4, 2019 | Reuters
By Clyde Russell
Shipments from Richards Bay declined to 73.5 million tonnes in 2018 from 76.5 million the prior year, well below the 91 million tonnes capacity of the terminal, which is the second-biggest in the world behind Newcastle Port in Australia.
Company News
Industry News
International News
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Mining entities awarded for safety efforts
Feb 3, 2019 | The Register-Herald (WV)
By Matt Combs
Last week, at its annual West Virginia Mining Symposium, the West Virginia Coal Association recognized companies for their efforts in safety and in mine reclamation.
“Safety always has been and continues to be our top priority in the coal industry,” Coal Association Senior Vice President Chris Hamilton said in a news release. “It’s always a proud day for us when we recognize those who excel in safety and demonstrate the highest levels of dedication to protecting our coal miners.”
Among those recognized, several southern West Virginia mines took home awards.
For Region Two, Lower War Eagle Mine in Wyoming County was recognized for safety for an underground mine and Coal Mountain Number One, also in Wyoming County, was recognized for safety as a surface mine.
For Region Four, Affinity Mine and Beckley Pocahontas Mine, both in Raleigh County, and Kingston Number Two in Fayette County were recognized for safety as an underground mine.
As for surface mines in Region Four, the Republic Surface Mine, Fayette County, the Tommy Creek Highwall Mine, Raleigh County, the Lost Flats Surface Mine and the Blue Knob Surface Mine, both in Greenbrier County, were recognized for safety.
Along with coal mines, the association also recognized Beckley Quarry in Raleigh County for safety.
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Experts do not foresee coal M&A, capex in 2019; sector, banks wary of investment
Feb 1, 2019 | S&P Global Market Intelligence (Online)
By Ellie Potter
While U.S. coal producers are hesitant to invest in new capacity at the moment, several industry professionals said at a recent energy event that they do not foresee widespread consolidation any time soon.
Michael Bauersachs, president and CEO of Ramaco Resources Inc., said that in a "difficult environment" where the sector's share prices are undervalued and investors are unwilling to take on debt, substantial mergers and acquisitions are unlikely.
"Now should it happen is a different question," he said during a panel Jan. 31 at the 19th Coaltrans USA conference in Miami. "In particular on the steam side, I think you could make the case that substantial consolidation makes a lot of sense. It makes a lot of sense in the Powder River Basin because nobody is making any money at all there."
Clarksons Platou Securities analyst Jeremy Sussman said boards are "uber sensitive to take on risk," something he doesn't foresee changing in 2019. Many investors were creditors who inherited their positions from coal bankruptcies, he said, and are not looking for growth at this point.
Banks also are hesitant to invest in capacity. While many banks refuse to fund thermal coal projects, "the vast majority will at least be willing to take a look at met coal," Sussman told S&P Global Market Intelligence in an interview.
"Compared to where it was when I began my career in 2006, it's still a small fraction of what banks were willing to give out back then," Sussman said. "Access to capital as a whole is still very, very tight."
Bauersachs said securing financing is more difficult now than at any other time in his three decades in the industry.
"This is a totally different type of atmosphere than I have seen. We've even seen private equity kind of stand to the side and not do much," he said. "I think with some of the environmental concerns, which obviously most of us in this room don't agree with, but with large U.S. banks I mean it's virtually impossible to do any business with them."
Matt Schicke, chief commercial officer of Corsa Coal Corp., said companies are not investing much money in their capital base, largely because of the "challenging times" the sector has faced the last three or four years. The lack of investment could yield subsequent rounds of consolidation and restructurings, he said.
"It can create a real challenge if there's a market downturn," Schicke said.
Another Ramaco Resources executive projects the sector will not look toward consolidation for about two more years as it waits for the markets to settle down. Until those investors who lost big in the last downturn get their money back, "you're really not going to see too much new money come back into the space," CFO and director Randall Atkins said.
"The way I look at the market today is you have a whole lot of institutional investors, a whole lot of banks that lost a whole lot of money," Atkins said.
Jonathan Rose, head of the metals and mining Americas division at Deutsche Bank Securities, said recent mergers and acquisitions were "more situation-specific" and subsequent movements in the sector will be "relatively slow." Further consolidation or acquisitions will likely occur because of specific opportunities rather than a wave across the industry, he said.
Consolidation will eventually be inevitable, Sussman said, because without investment in new capacity, supply growth will be "extremely limited." He projects metallurgical coal pricing will remain well above the cost of marginal production for the foreseeable future, while thermal coal demand will continue to decline domestically.
"It's a waiting game," he said. "It's about keeping a lean balance sheet and just hunkering down and generating cash and in most cases trying to return that cash to shareholders."
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Ohio warns potential buyer of certain Westmoreland coal assets may be blocked
Feb 1, 2019 | S&P Global Market Intelligence (Online)
By Taylor Kuykendall
Ohio environmental officials warned a bankruptcy court that the potential stalking horse buyers of certain Westmoreland Coal Co. assets may be prohibited from operating the purchased coal mines.
The Ohio Environmental Protection Agency and the state's Department of Natural Resources filed a joint motion Feb. 1 saying the state "is highly concerned" about whether Thomas and Ana Clarke, the potential buyers of Westmoreland's Oxford mines and Buckingham mines, have the assets to fund all reclamation and surface water mitigation requirements. The filing adds that the buyers may also be blocked from obtaining permits for the mines.
The filing said Westmoreland Coal and its affiliated entities have failed to comply with mitigation performance standards for stream and wetland impacts for years. The company has also "conducted unpermitted filling of wetlands and streams" on properties related to the Oxford assets. Enforcement of those requirements is pending with the Environmental Enforcement Section of the Ohio Attorney General's Office.
Based on a review of the U.S. Office of Surface Mining Reclamation and Enforcement's Applicant Violator System, the state has asked the federal agency to determine if there may be cause to block the transfer of permits to the stalking horse bidders, Sabine Pass Coal Co. LLC and Bayou Coal Partners LLC. The filing said information received by Ohio indicates that Ana Clarke is an officer and director of the stalking horse bidders while Thomas Clarke is listed as an "authorized signatory" in court documents, suggesting he has ownership or control of, or serves in an official capacity for, the stalking horse bidders.
Based on information received from federal officials, entities controlled or owned by both Clarkes "would be blocked from receiving coal mining and reclamation permits," the Ohio agencies wrote.
The Ohio entities are requesting that no sale hearing be held until the Ohio Department of Natural Resources receives transfer permit applications and can determine if the selected buyers are permit blocked.
Thomas Clarke has been behind several purchases of distressed coal assets in recent years, beginning with the acquisition of certain Patriot Coal Corp. assets. He also bought the assets that formed Mission Coal Co. LLC, which is in the midst of a bankruptcy reorganization. In a November 2018 bankruptcy court filing, unsecured creditors in the Mission case alleged a pattern in which Clarke acquires a legitimate company, leverages that company to take in substantial funds, pays those funds out in the form of management fees and then defaults on the acquired company's debts or otherwise delays or ignores payments to creditors.
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Westmoreland moves to end coal contract with Colstrip
Feb 3, 2019 | Casper Star-Tribune (WY)
By Tom Lutey
Plans are in the works to end the supply contract between Colstrip power plant and the coal mine that’s kept it firing for more than 40 years.
Ending the contract could result in the power plant shutting down, utility owners said, either because the power plant lost its only coal source, or because a new agreement with higher coal prices made Colstrip uneconomical.
Owners of the four-unit southeast Montana power plant filed objections Friday in U.S. Bankruptcy Court, where debt-plagued Westmoreland Coal Co. is trying to pass Rosebud Mine to creditors. The mine is practically across the street from the power plant.
The power plant owners Puget Sound Energy, Avista Corp., NorthWestern Energy, PacifiCorp, Portland General Electric and Talen Energy had balked at an earlier supply offer from Westmoreland. Now they’re being told to take the deal or else.
“Westmoreland’s most recent offer to the Colstrip owners would very likely make operation of Colstrip Units 3 and 4 uneconomic for not only Talen Montana but all of the fellow Colstrip owners,” said Taryne Williams of Talen Energy, a power plant co-owner who also keeps Colstrip running. Units 3 and 4 are the power plant’s workhorse units with the longest life expectancy.
“Additionally, while at the present time, there has been no decision to shut down Units 1 and 2 prior to the previously announced closure date of July 1, 2022, we continue to experience financial challenges related to keeping the units open,” Williams said.
There are already concerns about Colstrip power plant’s operating costs and mine bankruptcy in Washington state, where 1.8 million customers receive Colstrip power. Regulators have voiced concerns about the risks of feeding Colstrip power plant from a single mine.
Colstrip power plant is exclusively fed Rosebud coal — it’s designed for it, according to NorthWestern Energy. Montana’s largest monopoly utility, NorthWestern told the court that it would take up to three years of planning and permitting to begin feeding Colstrip with coal from another mine. During that time, the power plant would be shut down.
“If the Court allows (Westmoreland) to reject the Coal Supply Agreement, the Colstrip Complex will cease operation, and the Units will shut down and cease generating electricity in the middle of the Montana winter,” NorthWestern told the bankruptcy court. “The Colstrip Co-Owners will not be able to replace the coal supply right away, and the Units will close.”
The balance of electricity in the Pacific Northwest will be at risk, NorthWestern said.
“The Rosebud Mine is the only viable source of fuel for the Colstrip units,” said Grant Ringel, of Puget Sound Energy. “There are existing permit conditions that require local coal to be burned in those units.”
Puget evenly splits ownership of Units 1 and 2 with Talen and has 25 percent ownership of Units 3 and 4, making the Seattle-area utility Colstrip’s largest stakeholder. Asked if higher coal prices could push Units 1 and 2 into earlier retirement, Ringel said it would be challenging.
“The Colstrip units are under strong economic pressure from other sources of electric generation, especially natural gas. Anything that raises costs for Colstrip further weakens their competitiveness,” Ringel said.
Talen is the most vulnerable of the utility owners to a rise in coal prices. The Pennsylvania-based utility sells its power on the open market, where cheap electricity generated by natural gas or renewable energy are already eroding coal’s competitiveness. A decade ago, coal-power accounted for 40 percent of U.S. electricity, but today that number has fallen into the 20s, according to the U.S. Energy Information Administration.
“Talen Montana has made hard-won progress to improve the financial condition of Units 1 and 2. However, if Westmoreland rejects our current contract or increases our cost, the financial issues associated with the operation of Units 1 and 2 will likely get worse,” Williams said.
Talen aside, the other five Colstrip owners are regulated utilities with captive customers who pay higher-than-market prices, though they would need approval by state regulators to pass on higher coal costs to customers. Some regulators have already expressed concern about the price of Colstrip power.
It’s unlikely Rosebud Mine coal would go anywhere other than Colstrip power plant, said Seth Feaster, data analyst for the Institute for Energy Economics and Financial Analysis. The most likely non-Colstrip buyers for Rosebud Mine coal are probably in the Asian Pacific, where Powder River Basin companies like Cloud Peak and Aubre Energy already ship coal more affordably than Rosebud would.
The mine’s more probable play is leveraging a higher price from the Colstrip power plant. The challenge is raising coal prices without driving utilities toward gas or renewable energy, Feaster said.
“Coal companies depend on the power industry, but the power industry really doesn’t depend as much on coal,” Feaster said. “The coal companies are in a really bad spot because the moment they raise prices, the power companies are going to switch to something else. But if they don’t raise prices, their financial health is in peril.”
Westmoreland filed for bankruptcy in October. The Colorado-based company, with three mines and more than 400 employees in Montana, claimed more than $1.4 billion in debt and total assets of $770 million as of Aug. 31, 2018.
The company attempted to solicit bids from qualified buyers earlier this month, but received no offers other than the minimum bid from creditors pre-set to make sure Westmoreland’s debts were paid.
No one came forward with an acceptable offer, and now creditors are positioned to take both the core assets, like Rosebud, and several non-core assets, like the Absaloka mine near Crow Agency.
The supply contract to the Colstrip power plant isn’t the only agreement Westmoreland and its creditors seek to nullify.
Westmoreland needs to convince the U.S. Bankruptcy Court in the Southern District of Texas today to discard the coal company’s roughly $329 million in unsecured pension and benefits obligations owed mostly to the members of United Mine Workers. Creditors aren’t willing to acquire the mining company’s Wyoming assets with the pensions in tow.
There have been no objections to the pension and benefits plans attached to Westmoreland’s Montana mines, although that debt is also unsecured.
Age, consumer concerns about climate change and competition from natural gas and renewable energy are working against Colstrip power plant.
Four of the power plant’s six utility owners are poised to move away from coal power within eight to 10 years. In Washington state, where 1.8 million customers draw Colstrip power, the Legislature and governor are considering a ban on coal power by 2025.
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Powder River Basin coal production down in Q4'18, flat to year-ago period
Feb 4, 2019 | S&P Global Market Intelligence (Online)
By Taylor Kuykendall
Powder River Basin coal production fell from 86.6 million tons in the third quarter of 2018 to 83.9 million tons in the fourth quarter, a figure slightly higher than the fourth quarter of 2017.
Total annual production from the 16 active coal mines in the region fell by 3.0% in 2018 compared to the prior year, an S&P Global Market Intelligence analysis of mining data shows. The region primarily produces thermal coal and has some of the largest coal mines in the country.
The Powder River Basin has seen announced production cutbacks and other signs of major "winds of change," Hanou Energy Consulting LLC's John Hanou said in a recent report. For example, Westmoreland Coal Co. is in the middle of a bankruptcy restructuring, and Cloud Peak Energy Inc. is exploring strategic alternatives including a potential sale of the company.
"The bottom line is that the [Powder River Basin] is not in a healthy state; one that may not be reversible," Hanou wrote.
Coal production from Peabody Energy Corp.'s North Antelope Rochelle mine, the largest coal mine in the U.S., decreased from about 26.1 million tons in the third quarter of 2018 to 24.5 million tons in the fourth quarter. Production from Peabody's Caballo mine was up 1.9% in 2018 compared to 2017, while the company decreased coal production at its Rawhide mine by 8.1%.
"I think we should take the five-year picture that the overall market is in decline," Peabody President and CEO Glenn Kellow said on an October 2018 call in response to an analyst asking for an outlook on 2019 production from the Powder River Basin. "But 2018, as you indicated, was the — probably the biggest year of that in terms of [power plant] retirements. And how we see it playing out is purely going to be a function of GDP. Gas prices and weather conditions will determine what that movement is going through into 2019."
Arch Coal Inc. decreased coal production at its Black Thunder coal mine from 19.4 million tons in the third quarter of 2018 to 17.6 million tons in the most recent quarter. For the year, Arch increased production from the mine slightly from 70.5 million tons in 2017 to 71.1 million tons in 2018.
"You're still seeing utilities that are very comfortable with letting their inventories drop," Arch Coal COO Paul Lang on a call reporting third-quarter results. "At some point, things will have to start picking back up. But right now, I don't see a lot of pressure on the side of utilities."
Arch decreased production from its Coal Creek mine by about 10.9% in 2018 compared to the prior period.
Coal production from Cloud Peak's three mines in the region — Antelope, Spring Creek and Cordero Rojo — totaled about 12.9 million tons in the fourth quarter of 2018. That is up slightly from third-quarter production, but down from 13.7 million tons produced in the year-ago period. Cloud Peak's total production in 2018 was down 14% to 49.5 million tons.
Blackjewel LLC increased production at its Belle Ayr mine by about 16.7% to a total of 18.5 million tons of coal in 2018 compared to 2017. The company reduced production from the Eagle Butte mine by about 1.2% to 17.1 million tons in the same period.
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Cleanup of Montana Coal Train Derailment Could Take Weeks
Feb 1, 2019 | Associated Press (Online)
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Indiana Shipping Ports See Big Jump in Cargo Shipments
Feb 4, 2019 | Associated Press (Online)
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Sick and Struggling in Coal Country
Feb 4, 2019 | Associated Press (Online)
By Binghui Bang
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MSHA looks to 'difficult solutions' to lower miner dust exposure, official says
Feb 3, 2019 | S&P Global Market Intelligence (Online)
By Taylor Kuykendall
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Lawmakers make new push for retired miners
| E&E News
By Dylan Brown
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Va. lawmakers reject plan to phase out fossil fuels
Feb 1, 2019 | S&P Global Market Intelligence
By Darren Sweeney
Virginia lawmakers shot down a plan to phase out the use of fossil fuels and transition the state to 100% clean energy.
The Virginia House of Delegates voted 51-48 along party lines Jan. 31 to reject several amendments before ultimately voting 86-12 to reject House Bill 1635.
H.B. 1635, prefiled in November 2018 by Del. Sam Rasoul, would establish a moratorium on Virginia State Corporation Commission approval of generation facilities using fossil fuels beginning in 2020 and would require 100% of electricity sold at retail in the state to come from renewable resources by 2036.
A floor substitute Rasoul offered also failed. It would require 30% of electricity sold by a retail electric supplier to be generated by clean energy resources from 2030 through 2050 before increasing to 100% after 2050.
The original legislation also sought a moratorium on permitting approval for "any new gathering line or pipeline for the transport of any fossil fuel resource that requires the use of eminent domain on private property," effective Jan. 1, 2020.
Richmond, Va.-headquartered Dominion Energy Inc. is the majority owner and lead developer of the Atlantic Coast Pipeline LLC natural gas transportation project. The 600-mile, 1.5-Bcf/d pipeline is expected to run from West Virginia through Virginia and North Carolina to deliver Appalachian gas to downstream mid-Atlantic and Southern markets.
It has been tied up in numerous court challenges brought by landowners and environmental groups, as well as permit disputes.
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Ala. utility plans to close coal-fired plant, citing US EPA coal ash rule
Feb 4, 2019 | S&P Global Market Intelligence (Online)
By Zack Hale
PowerSouth Energy Cooperative will retire its coal-fired Charles R. Lowman plant due to federal coal ash regulations, the utility's CEO said.
The 556-MW plant's three units will be replaced with natural gas-fired generation, CEO Gary Smith told employees in a Dec. 31, 2018, message. Smith cited the U.S. Environmental Protection Agency's Coal Combustion Residuals, or CCR, rule as the driving force behind the move.
PowerSouth Energy representatives did not immediately respond to requests for additional comment on Jan. 31. The generation and transmission cooperative supplies wholesale electricity to 16 distribution cooperatives and four municipal utilities in Alabama and the Florida panhandle.
Issued by the Obama administration in 2015, the CCR rule set the first-ever national standards for the safe storage and handling of coal residuals, also commonly referred to as coal ash. Like most coal plants of its era, the Lowman plant disposes of coal ash and other residuals from burning the fuel for electricity in clay holding ponds. The problem is that those ponds — now technically considered "unlined" under current regulations —can leach toxic pollutants into the underlying groundwater, which can then contaminate nearby surface waters.
The original CCR rule gave power plant operators until Oct. 17, 2018, to demonstrate compliance, and those that failed to do so had an additional six months to initiate closure of impoundments that did not meet the rule's requirements. But the EPA in July 2018 finalized changes extending the deadline for initiating closure to Oct. 31, 2020, in response to concerns raised by utilities. In addition, the U.S. Court of Appeals for the District of Columbia Circuit in August 2018 found the original CCR rule's provision that unlined impoundments need only initiate closure or retrofit after they are found to violate groundwater protection standards was not sufficiently protective.
"Because we will not be able to move coal ash to our ponds after October 2020, we are left few choices other than to close the Lowman Plant and obtain additional generation resources to replace the coal-fired generation," Smith told employees. The CEO lamented the loss, noting the shift will make PowerSouth Energy Cooperative more dependent on gas-fired generation. In his December 2018 message, Smith said the Lowman plant was economically dispatched ahead of the co-op's most efficient gas-fired units for the previous four weeks due to higher gas prices. "With the closure of the Lowman plant, we lose the diversity of coal-fired generation as a natural hedge against higher natural gas prices," he said.
Original Lowman unit operating for 50 years
The first unit at the Lowman plant, in Washington County, Ala., began operating in 1969 and has a nameplate capacity of 66 MW, according to S&P Global Market Intelligence data. Two other units, each with a nameplate capacity of 236 MW, began operating in 1978 and 1980. The plant's primary source of coal in 2018 was Alliance Resource Partners LP's Gibson mine in Indiana.
According to S&P Global Market Intelligence capacity factor data through October 2018, which measures the percentage of hours the plant was in operation, the plant's highest use was in high-demand months of July and August, at nearly 60%. However, the plant was hardly used between February and June.
PowerSouth's overall generation portfolio totals nearly 2,000 MW of nameplate capacity, and is already two-thirds natural gas. In October 2018, the utility issued a request for proposals for up to 80 MW of solar capacity to be in service by Oct. 31, 2022.
The plant closure was announced a month before Fitch Ratings on Jan. 31 downgraded $97 million in PowerSouth bonds to BBB+ from A-, with a negative outlook. The downgrade was prompted by the utility's "anticipated increase in financial leverage" related to its contract to buy 125 MW from the troubled Vogtle nuclear project through the Municipal Electric Authority of Georgia, as well as higher debt needed for major capital expenses.
Fitch said PowerSouth plans to add baseload, natural gas-fired generating capacity by 2023, and has a 631-MW facility in mind, and peaking capacity by 2027.
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Feb 2, 2019 | The Roanoke Times (VA)
By Jennifer Fernandez
Five years ago Saturday, a drainage pipe under a coal ash pond at the Dan River Steam Station near Eden ruptured, spilling up to 39,000 tons of the cloudy waste into the river.
It marked the third-largest coal ash spill in U.S. history.
The spill led to federal charges and fines against the Charlotte-based utility and spurred passage of a new state law requiring all coal ash storage ponds be closed by 2029.
The N.C. Department of Environmental Quality held a round of community meetings last month to discuss closure plans at six sites considered “low-risk.”
The Dan River site is one of four “priority” sites originally slated to be closed by this August.
On this fifth anniversary of the spill, here is a look back at what caused it and where the cleanup stands today.
The spill
On the afternoon of that Super Bowl Sunday, a guard patrolling the Dan River Steam Station noticed one of the coal ash storage ponds looked suspiciously low.
By midnight, a platoon of environmental experts was on the scene, trying to stanch the third-largest coal ash spill in U.S. history.
The U.S. Environmental Protection Agency would later describe what happened that day at the retired power plant near Eden as the “sudden collapse” of a drainage pipe running under the main pond.
But the problems that led to that collapse were years in the making: years of coal-fired power production at the riverside power plant; years of burned coal waste accumulating in the nearby ponds; years of corrosion and seepage eating a seam into a vulnerable metal pipe beneath 1 million tons of coal ash; years of Duke Energy giving short shrift to early warnings from engineers about that very pipe; and years of state officials not always holding utility executives to high-enough dam safety standards.
Within five days, work crews had plugged the damaged drainage line. They also later closed off a second, smaller drainage line nearby that turned out to be leaking pollutants into the river.
Coal ash — what remains after power plants burn coal to produce electricity — is not classified as a hazardous material. But it contains trace elements of such chemicals as arsenic, hexavalent chromium, selenium and vanadium that can threaten water quality given the gigantic quantities of ash that Duke Energy has amassed at 14 sites across North Carolina.
Environmental groups worry about the future health of the river.
“We know coal ash and substances like arsenic do not go away, they don’t disappear, they don’t evaporate,” said Frank Holleman, senior attorney with the Chapel Hill-based Southern Environmental Law Center, which has sued Duke Energy over its coal ash handling on behalf of various groups, including four nonprofit river guardians and the state NAACP.
“Every time it floods, some of those materials are being deposited on land surrounding the Dan River,” he said, adding that the spill continues to affect the ecosystem.
State environmental officials told the Danville Register and Bee this week the impact on the river has been minimal, with fish consumption advisories at the same level as they were before the spill.
The spill at the old Dan River Steam Station’s storage pond coated the river bottom with toxic ash as far as 70 miles downstream.
By late July 2014, Duke Energy ended efforts to recover the spilled coal ash after collecting about 10 percent, representing the three largest deposits that had settled in the Dan River, all the way downstream to Danville.
In collecting those deposits, the utility used what amounted to a gigantic, underwater vacuum cleaner atop a dredge barge to first stir up the top layer of coal ash then suck up the cloud of ash and debris. The next step screened out larger debris, sand and other junk. After that, the remaining water with coal ash was cleaned as the fine particles of contaminated material settled to the bottom for further processing. Clean water was sent back to the Dan River. The underlying polluted material was sent to the next stage, where special polymers were added and any remaining water squeezed out. The remaining, dried-out mixture was hauled away to a double-lined landfill about 30 miles away, near Rougemont, N.C., in Person County.
Federal and state officials authorized Duke to stop the removal effort after the large deposits were cleaned up. They said that continuing to remove more of the coal ash might do more harm than good by stirring up submerged pollution from other industries long ago.
Even before the Dan River spill, Duke had begun to phase out some of its coal-fired plants.
The Dan River plant, which was demolished in 2016, had already been replaced in 2012 by a more modern, natural gas-fired plant.
Seven of Duke Energy’s 14 coal-fired plants in the state have been decommissioned.
Dan River station today
Cleaning up about 4.2 million tons of coal ash takes time and money.
Duke Energy expects it will have spent at least $260 million to dig up and move offsite or into a new, lined landfill for the coal ash stored at the Dan River site.
In all, the utility looks to spend at least $5.7 billion safely storing North Carolina’s close to 133 million tons of coal ash deposits.
“The company has really worked hard in the last five years to be a leader in managing coal ash,” said Duke Energy spokeswoman Paige Sheehan.
The burst pipe at the Dan River station in 2014 propelled the utility giant down a yearslong cleanup path there.
Duke first dug up and hauled out about 1.2 million tons of the waste, sending it by train to the privately-owned Maplewood Landfill near Jetersville in Amelia County. That part of the cleanup finished in spring 2017.
Michael Dougherty, Eden’s director of economic development, said he watched some of the removal process. It was “pretty remarkable how carefully” the ash deposits were transferred to the trains and covered for transport to Virginia, he said.
In addition, about 112,000 tons have been recycled so far by a Virginia cement kiln.
Workers have been moving the rest of the waste stored at the Dan River site to a new, lined landfill on the same property that will hold some 2.8 million tons of ash when work there is complete, Sheehan said.
The basin closure plans vary by site. Some, like Dan River, will be excavated with the waste moved to new, lined landfills on site.
Some would keep the ash in place, with the pile covered by an impervious cap of thick plastic sheeting and layers of soil. The cover would keep the ash dry and prevent it from spreading pollution, say Duke Energy officials and consultants. Other sites will reprocess some of the ash onsite to make it suitable for recycling into concrete.
Holleman, the environmental lawyer, says Duke should move all of the ash to lined landfills like the one at the Dan River site.
While no landfill is perfect, he said, the modern, lined landfills are preferable to keeping the ash in unlined basins that can leak into groundwater or nearby waterways.
Under state law, drawn up in response to the Dan River spill, Duke has until August to remove all of the coal ash from the former storage ponds at the now-shuttered coal-fired plant.
The onsite landfill is lined with clay and designed to catch and direct water runoff into a pipe that sends it to Eden for treatment.
Storage basins at three other plants were also originally slated to be closed by this August.
The Asheville plant got a reprieve until 2022, although two of the three basins there have already been excavated. Sheehan said the work there is on track. More than 6 million tons have been excavated there, the latest data show.
Duke recently sought an extension until February 2020 for the Sutton plant in Wilmington, which was hit hard last year by back-to-back hurricanes. The storms delayed and hampered cleanup efforts of the storage basins there, according to media reports.
More than 5.2 million tons have been excavated there.
More than 5 million tons have been excavated at the Riverbend station in Mount Holly, the other site slated to close by August.
Sheehan said Duke Energy expects to meet the August deadline for the Dan River site.
Eden’s Dougherty praised the utility for its work to remediate the spill. The company has put millions of dollars into the region that have helped smaller towns and cities, like Eden, add trails and improve access to the Dan River.
“I really think they did the best they could to remedy this in an appropriate way,” he said.
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Georgia Power plans to add 1,000 MW of renewable capacity, remove 5 coal units
Feb 2, 2019 | S&P Global Market Intelligence
By Darren Sweeney
Georgia Power Co. plans to add up to 1,000 MW of new renewable resources to its portfolio and shut down five coal units as part of its 20-year resource plan filed with state regulators.
Georgia Power on Jan. 31 filed its 2019 integrated resource plan, or IRP, with the Georgia Public Service Commission.
The Southern Co. subsidiary said in a news release that it is proposing new renewable energy programs as part of the plan, including a request to procure up to 1,000 MW of renewable resources. If the request is approved, Georgia Power said its total renewable energy capacity would increase to 18% of its portfolio by 2024.
The utility also proposes energy efficiency targets similar to those approved in its previous IRPs, but with new energy-saving programs for residential and commercial customers. "By 2022, these programs are designed to help reduce peak demand approximately 1,600 MW, which is 10 percent of the company's current peak demand," Georgia Power said in the news release.
In addition, the company is requesting to remove from service all four units at its 840-MW Hammond coal plant in Floyd County, Ga., and to shut down its 142.5-MW McIntosh coal unit in Effingham County, Ga.
The plan does not contain specific retirement dates for the Hammond or McIntosh units. Three units at the Hammond plant have been operating since the mid-1950s, according to S&P Global Market Intelligence data, and unit 4, with a nameplate capacity of 578 MW, has been operating since 1970. The plant is not frequently used, typically only in high-demand summer and winter months, according to S&P Global Market Intelligence capacity factor data. Its primary source of coal in 2018 was the MC No. 1 mine in Franklin County, Ill., co-owned by Murray Energy Corp. and Foresight Energy LP.
Georgia Power said it also is seeking approval to issue two requests for proposals for future generation needs, as it acknowledges "the continued economic pressure felt on coal-fired units," including units 1 and 2 at its 3,232-MW Bowen plant in Bartow County, Ga.
As part of its IRP, the utility is proposing not to renew the operating licenses for the Langdale and Riverview hydroelectric facilities, both of which are nearly a century old and each with capacity of less than 1 MW, and is seeking approval of its environmental compliance strategy. Georgia Power has filed plans to close all of its coal ash ponds to meet the U.S. Environmental Protection Agency's Coal Combustion Residuals rule and Georgia's coal ash management mandates. (Georgia PSC Docket No. 42310)
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Advocates see 'real opportunity' to cap carbon
| E&E News
By Benjamin Storrow
After toying with the idea for more than a decade, Oregon may finally be on the verge of putting in place a cap-and-trade system for carbon.
Last week, lawmakers unveiled a bill several years in the making that calls for cutting emissions 45 percent of 1990 levels by 2035 and 80 percent by 2050. The measure would cap emissions beginning in 2021 and give utilities a decade before they have to buy carbon credits. It would also provide a declining number of allowances to trade-exposed industries.
Most importantly, the bill would provide the framework for Oregon to become the first state to link with California's cap-and-trade system.
"Overall this is extremely exciting. These are appropriately ambitious targets. It puts Oregon on track to be among the leading jurisdictions in the world on climate mitigation," said Noah Long, who leads the Natural Resources Defense Council's climate and clean energy program in the Northwest.
Oregon's past cap-and-trade ambitions have been thwarted by the recession and by the election of President Obama and the resulting shift in greens' attention toward Washington, D.C.
Advocates of cap and trade thought they had enough support to pass legislation last year. Ultimately, though, they were unable to get a bill across the finish line during the Legislature's short off-year 30-day session (Climatewire, March 1, 2018).
This year, Gov. Kate Brown (D) and legislative leaders have signaled cap and trade is a priority for the session in Salem.
The new legislation arrives at a critical time on several fronts. Oregon's emissions rose slightly in 2017 to roughly 65 million metric tons of carbon, according to a recent state report. The state is unlikely to meet its emissions targets for 2020, when carbon levels were supposed to fall to 51 million metric tons.
A legislative win also would breathe new wind into the sails of climate hawks nationwide after a series of high-profile defeats on carbon pricing. Several attempts at a carbon tax in neighboring Washington state have failed in recent years.
If Oregon is successful this year, a new crop of Democratic governors in Colorado, Nevada and New Mexico might take a closer look at cap and trade, said Angus Duncan, president of the Bonneville Environmental Foundation and the head of the Oregon Global Warming Commission.
Just last week, New Mexico Gov. Michelle Lujan Grisham (D) said her state would explore a market-based approach for reducing emissions (Climatewire, Jan. 30).
"We have to show them this is a real opportunity and we have a chance of getting some movement back toward us. We haven't shown that up to now, but that's why Oregon is of such strategic importance," Duncan said. "By the time the 2020 election rolls around, we could have either have or have in training a Western movement that is multistate."
The extra year may ultimately have been to Oregon's benefit. The state's utilities were wary of the 2018 bill. But a provision providing them free carbon allowances through 2030 appears to have softened the opposition.
The move recognizes Oregon's existing efforts to green the power sector, said state Sen. Michael Dembrow (D), a leading proponent of the legislation. In 2016, Oregon passed a law requiring its utilities to phase out coal-fired power imported from outside the state and boosting its renewable portfolio standard to 50 percent by 2040.
"They are already passing decarbonization costs onto ratepayers, so we didn't want to double price the ratepayer," Dembrow said.
A spokesman for PacifiCorp said the Portland-based power company was reviewing the measure. Portland General Electric signaled its approval of the bill.
"It contains and complements existing policies that intend to both drive us and incent us toward carbon reductions while protecting our customers from significant rate impacts that we would expect to see if direct allocation was not included," said Steve Corson, a Portland General Electric spokesman.
Some hurdles remain. Perhaps the biggest question is whether the proposal constitutes a tax. If it did, the bill would need three-fifths support in the Legislature to pass. Dembrow and others nevertheless expressed confidence that the legislation has been structured in such a way that it would overcome the tax concerns.
This much is clear: Oregon greens likely have never had such a good opportunity at putting a price on carbon. Now, they actually have to pass it.
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Deep freeze prompts Trump administration to re-up bid to bolster coal plants
Feb 2, 2019 | Washington Examiner (DC)
By Josh Siegel
The Trump administration is relitigating its arguments supporting coal after the fading fuel source was used more frequently this week to help meet surging power demand during the deep freeze that overtook the Midwest and East Coast.
Steven Winberg, the Energy Department’s assistant secretary for fossil energy, touted early data Friday showing coal and nuclear generated a higher percentage of power during the cold surge than usual. Temperatures were expected to return to normal this weekend.
“People will pore over the data, and one thing you will see is coal will have stepped up its capacity factors, and nuclear will have stepped up its capacity factors," Winberg told the Washington Examiner in an interview. "Those are power sources that have fuel on the ground, and that's absolutely important. If we didn't have that, it would have been a much worse situation."
The Trump administration has repeatedly cited the stress of extreme cold weather events as a possible reason to subsidize coal and nuclear plants, which can store fuel on-site. Natural gas, normally the cheapest and most-used fuel for electricity, depends on pipeline flows that can be interrupted during extreme weather, while wind and solar power, whose prices have dramatically fallen, fluctuate depending on when the sun is shining and the wind is blowing.
President Trump has repeatedly pressed for action to save coal and nuclear plants, even after an independent panel of federal energy regulators rejected a Energy Department plan to provide them special payments because of a lack of evidence showing the grid is at risk.
The White House has stalled over an effort to use emergency executive authority to help coal and nuclear plants.
But the administration continues to promote the benefits of coal in the meantime, with this week’s cold weather presenting an opening.
As of Thursday morning, coal provided 37 percent of electricity this week in the nation’s largest power market run by PJM Interconnection, which includes 13 states from Illinois to the District of Columbia — according to data provided by the American Coalition for Clean Coal Electricity.
But PJM reported no reliability issues on its grid and has previously said its electricity supply would hold up against a range of threats, including extreme weather.
Also this week, coal served 51 percent of power in the Midcontinent ISO, representing 15 Midwest states.
Normally, coal provides about a third of the total power mix.
"What that continues to show is we need energy diversity and fuel diversity for electricity,” Winberg said. “The imperative is to keep the grid reliable and resilient."
Coal’s more frequent use coincided with record-breaking natural gas demand.
Natural gas consumption in the lower 48 states hit 150.6 billion cubic feet per day on Wednesday, according to estimates from S&P Global Platts, as consumers hiked their heaters to combat the cold.
That tops the previous high of 144.6 billion cubic feet per day set on Jan. 1, 2018, during last year’s “bomb cyclone.”
Some states, meanwhile, asked residents to turn down their thermostats to conserve natural gas.
Michigan utility Consumers Energy urged residents to lower their thermostats to 65 degrees Fahrenheit or less until Friday at noon after a compressor station in suburban Detroit caught fire, shutting down gas flow from the facility.
Utility Xcel Energy asked Minnesota residents to keep their heat at 63 degrees Fahrenheit through Thursday morning because of a “significant strain on our natural gas system due to extreme weather,” the company said. Both gave the all-clear by Friday.
“Coal is an insurance policy,” Michelle Bloodworth, president and CEO of American Coalition for Clean Coal Electricity, told the Washington Examiner, citing the compressor station fire. “It’s a hedge when bad things are happening.”
But despite the record natural gas demand, prices for it remained low this week, which supporters said showed the resilience of the gas and electric systems thanks to plentiful supply from the shale boom. That contrasts with last January’s “bomb cyclone," when average energy prices in the East Coast wholesale markets were more than four times higher than the average for the winter.
“With today's technology, there is no feasible constraint to the amount of natural gas available in the market, and that's why prices are lower,” Dean Foreman, chief economist of the American Petroleum Institute, the main oil and gas trade group, told the Washington Examiner. "That has taken the air out of arguments against gas’ resilience.”
Indeed, critics of the Trump administration’s bid to help coal and nuclear argue those energy sources do not protect the grid during extreme events.
The Rhodium Group, a research firm, said in a recent independent study that “of all the major power disruptions nationwide over the past five years, only 0.00007 percent were due to fuel supply problems. The vast majority were the result of severe weather knocking down power lines.”
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Opinion: America Should Better Utilize Advanced Coal
Feb 1, 2019 | Forbes
By Jude Clemente
Lest we forget:
"Advancing the development of clean coal technologies is an important part of President Obama’s strategy to develop every source of American energy and ensure the United States leads the world in the global clean energy race and continues to take advantage of domestic resources here at home,” said U.S. Energy Secretary Steven Chu, 2012
Indeed, one of the great myths in our ongoing energy-environment discussion is that only renewable energy systems are evolving. The reality, of course, is that fossil fuel-based technologies are constantly improving as well. Our use of fossil fuels is always becoming more efficient with systems needing less fuel (feed) to generate more energy and becoming cleaner by emitting less greenhouse gases.
Perhaps coal is the best example of this fact
The truth is that coal technologies continue to get better. To those of you that deny this, a title says a lot: energy adviser to the rich OECD nations, the International Energy Agency (IEA) houses a Clean Coal Center.
To reach environmental goals, IEA highly promotes what it dubs "High Efficiency, Low Emission" (HELE) advanced coal technologies. These are state-of-the-art supercritical and ultra-supercritical coal plants that can cut CO2 emissions over older plants, for instance, by 40% or more.
In "Outlook and Benefits of An Efficient U.S. Coal Fleet," leading researchers at Wood Mackenzie recently concluded that we have significant opportunity for HELE deployment here in the U.S. Others are quickly outpacing us in this critical arena. Under 30% of U.S. coal plants utilize HELE technologies, well below 66% in China, over 70% in Western Europe, and about 75% in Japan.
Regulatory barriers that make upgrading America's coal fleet to higher efficiency levels extremely expensive are a main reason why our fleet has fallen behind.
In November, Sen. Todd Young (R-Indiana) introduced the Reinvigorating American Energy Infrastructure Act to encourage better adoption of HELE advanced coal by expanding loan opportunities. As seen in the graphic below, far more than is being claimed, there is still solid support for coal in America. Per polling from Morning Consult just a few weeks ago, this is mainly based on the desire for a reliable, affordable, and diverse electric power system that coal helps install.
Coal, of course, is not "dead" here in the U.S. but still a major energy source: supplying 28% of all U.S. electricity last year. And coal plants are called on most in times of extreme cold like we saw this past week. The resiliency that coal supplies the power system in these tough times has been proven time and time again.
Coal is not going back to its glory days of just 15 years ago, when it was over half of all U.S. power, but it is hardly in freefall either. The U.S. Energy Information Administration's just released Annual Energy Outlook 2019 sees coal still supplying 25% of power in 2030, more than all renewables put together.
But coal's contribution could ultimately be higher than that. Coal will gain from Deep Electrification efforts that will surely mean more power demand, and any increase in gas prices, battery storage not evolving as claimed, and as related, intermittent renewables failing to deliver as promised would all help coal's chances. In fact, these potentials to lift coal are precisely why the Wood Mackenzie report delineated strategies to "foster" HELE deployment in the U.S.
Indeed, I personally believe that future U.S. electricity demand is being greatly underestimated, which underlines the importance of all-of-the-above energy strategy. IEA has told us repeatedly that U.S. energy policy must be practical: simply relying on intermittent wind and solar to reduce emissions will not get the job done.
Globally, coal supplies a leading 40% of all electricity, and is particularly vital to the energy-deprived poor countries that require low cost power. Measured in the billions of humans without proper access, the world is simply too energy short to take coal completely off the table. Former World Bank President Jim Yong Kim knew this, and called such needless suffering of the world's poor "energy apartheid." Being practical, he seeks a key role for more advanced coal:"If we find ourselves in a situation…where we say no coal…then we’re really not serious….We can’t say to African leaders well because of our other concerns, you're going to have wait on getting energy…we have to look at every single option...we know that intermittent energy has never led to economic development in any other country," Jim Yong Kim, President, World Bank, 2014
Research and investment into making coal cleaner is essential to our global goal of economic development and a cleaner environment. Evolving technologies, not incessant regulation, is the solution. Again, widely supported by President Obama, U.S. research in this space is very important because we can export cleaner HELE technologies to gain economic partners while also cutting emissions: "The United States As A Clean Coal Leader."
HELE is the first step to an imperative emission reduction strategy for coal that focuses on carbon capture and sequestration (CCS), a maturing technology to capture CO2 before its released into the atmosphere and then stored safely in the ground. CCS is supportedby the Intergovernmental Panel on Climate Change, the global authority. IEA consistently points out that without CCS reaching climate goals will costs trillions of dollars more, if they are even achieved at all.
According to IEA, "Combined with CCS, HELE technologies also can cut global average CO2 emissions from coal plants by as much as 90 percent."
As CCS systems continue to evolve, some good news that we all should celebrate: "Strong year for CCS at Boundary Dam power plant."
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India ramps up spending on coal exploration as it slashes funds for mine safety
Feb 1, 2019 | Reuters
By Sudarshan Varadhan
The Indian government will increase spending on exploration of coal and lignite by 20 percent in the coming financial year but will slash funding for coal mine safety and conservation, according to the federal budget document released on Friday.
India is one of the world’s largest consumers of coal and rising imports of the fuel are adding to a burgeoning trade deficit, prompting the government to invest in developing more domestic resources.
In the 2019/20 financial year that begins in April, the government aims to spend 6 billion rupees ($84 million) on exploration of coal and lignite, the document for the 2019/20 budget showed.
At the same time, it will cut spending on conservation, safety and related infrastructure development by about a third from last year to 1.35 billion rupees, according to the document.
India is one of the most dangerous countries in the world to be a coal miner, with one miner dying every six days on average in 2017, according to government data, but this will be the second straight year that the government has cut spending on safety.
The coal ministry said that coal companies had their own safety budgets.
State-run Coal India Ltd has a near monopoly, producing over four-fifths of the country’s coal output. It allocated 8.6 billion rupees for safety-related expenditure for the year ending March 2019, up from 8 billion rupees a year earlier, the ministry said in an emailed statement to Reuters.
It did not say how much it would allocate for safety-related spending in 2019/20.
India scrapped a separate excise duty levied on coal companies, which was used by the federal coal ministry to shore up funds for enhancing safety, after it reformed tax policies in 2017.
The coal ministry said it had increased spending for exploration in 2019/20 to develop more coal blocks to increase domestic coal production and minimize imports.
“This will also enable (the) release of more coal blocks for auction/allocation,” the ministry said.
In 2018, India’s thermal coal imports rose at the fastest pace in four years, according to two industry sources, despite moves by Prime Minister Narendra Modi’s government to cut imports. ($1 = 71.4230 Indian rupees) (Reporting by Sudarshan Varadhan; Editing by Susan Fenton)
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Opinion: South Africa will struggle to boost coal exports, even if it wants to: Russell
Feb 4, 2019 | Reuters
By Clyde Russell
There may be some irony in climate change being blamed for an increase in weather delays that resulted in South Africa’s coal exports dropping 4 percent last year, but in reality the rough seas at the country’s Richards Bay terminal are the least of the industry’s worries.
Shipments from Richards Bay declined to 73.5 million tonnes in 2018 from 76.5 million the prior year, well below the 91 million tonnes capacity of the terminal, which is the second-biggest in the world behind Newcastle Port in Australia.
The terminal lost 36 days of loading last year because of rough weather, down slightly from 38 days in 2017, with both these years being considerably higher than in preceding years.
But even if the terminal was fully available all 365 days of the year, it’s still unlikely that much more coal would have been shipped.
The blame for South Africa’s lower exports was placed on market conditions by the head of Richards Bay Coal Terminal (RBCT), Alan Waller, with high prices crimping demand in the main export destination of India.
However, RBCT chair Nosipho Siwisa-Damasane said the weather disruptions are also likely a challenge for future years, and terminals around the world were going to have to deal with the “new norm” of what was previously abnormal weather patterns.
While high prices were undoubtedly a contributing factor to the lower exports, it’s also likely that infrastructure constraints and an inability of many of South Africa’s coal miners to boost production were perhaps of greater importance.
The rail network has a theoretical capacity of delivering 81 million tonnes a year from South Africa’s inland mines to RBCT, meaning that even if it was working at full steam, there still wouldn’t be enough coal to use up RBCT’s export capacity.
Mandisa Mondi, the general manager of coal freight at state-owned rail operator Transnet told the IHS Markit Southern African Coal Conference in Cape Town last week that plans were in place to boost the rail capacity to match that of RBCT.
These include initial steps to improve technology and operational efficiencies to reduce bottlenecks, followed by later infrastructure improvements such as a new tunnel through a mountain between the inland coal fields and the coast.
Transnet said it could eventually boost the rail capacity available for exports by 25 million tonnes above current levels, but whether this happens depends on whether miners commit to producing and exporting more.
It’s here where the situation becomes less clear, with companies having been reluctant in recent years to invest in building new mines or even expanding existing operations.
Part of this was because of a long-running dispute over South Africa’s mining laws, although that appears to have been settled recently.CONFIDENCE LACKING?
Still, South Africa’s coal miners would have to take a positive view of likely demand before committing capital to new projects.
The IHS Markit conference heard some rosy forecasts of demand for coal, mainly on a surge in new power plants being built in India.
However, these forecasts are likely to prove hopelessly optimistic, especially as renewable energies become cheaper and more reliable, and as more liquefied natural gas (LNG) becomes available from projects in Australia, the United States and Russia.
Just under half of South Africa’s coal went to India in 2018, a country with an official policy of reducing coal imports to zero over time.
Other major buyers include South Korea, which also plans to lower coal burning, and Pakistan, which has concerns over the foreign exchange cost of importing fuels.
While South African coal is viewed as a good quality product, and superior to supplies from top thermal coal exporter Indonesia, there are serious questions as to whether there will be sufficient demand in Asia to justify spending the hundreds of millions of dollars needed to boost mine supply and rail capacity.
This makes it likely that South Africa will continue to be a relatively steady supplier of around 75 million tonnes of coal a year to the seaborne market.
This could increase somewhat if Transnet can de-bottleneck and RBCT doesn’t lose more days to rough weather.
But for now, any ambitious plans to boost coal exports are exactly that, just plans.
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