Moody’s Boosts North American Coal Industry Outlook

Despite persistent challenges, the outlook for the North American coal industry has been revised to stable from negative, Moody’s Investors Service said in a new report. A combination of fourth quarter 2016 metallurgical coal benchmark prices settling at $200 per metric ton (mt) and natural gas prices hovering around $3/MMbtu has provided immediate relief for the strained sector.

The rating agency has also revised its price sensitivity assumptions for seaborne coal prices. In the medium-term range, met coal has been lifted to $90-$130/mt from $85-$90/mt, and Newcastle Thermal assumptions have been increased to $50-$65/mt from $53-$58/mt.

“Although we do not view the recent price uptick in met coal as ultimately sustainable, we also are not expecting prices to return to the low levels seen in late 2015 and early 2016, which were themselves a function of an oversupplied market and miners still working through production rationalizations,” said Anna Zubets-Anderson, Moody’s vice president, senior analyst.

Even as U.S. metallurgical coal producers have significantly cut back production, they will continue to be disadvantaged by longer distance to the Asian markets, a strong U.S. dollar and higher position on the cost curve.

Additionally, Moody’s analysts expect the U.S. thermal coal industry has seen the bottom due to rising natural gas prices and rationalization of production, even as the Energy Information Association (EIA) anticipates a decline in coal consumption of 9% in 2016 due to Mercury and Air Toxics Standards (MATS) implementation, and only a modest recovery in 2017 due to growth in electric generation.

“For the thermal coal industry, the increase in natural gas prices has been supportive to a material price recovery across all U.S. coal basins,” Zubets-Anderson said.

An additional boost to the struggling sector is the likely benefit from consolidation, as major U.S. coal producers emerge from Chapter 11 reorganization with debt levels Moody’s believes will be maintained at a fraction of their pre-filing amounts.

Corsa to Open Acosta Mine

Noting that spot prices for metallurgical coal have surged recently, Corsa Coal Corp. plans to increase production and sell significantly more tons of metallurgical coal over the coming quarters. The company has commenced development work at Acosta, a deep mine in Somerset County, Pennsylvania, which is forecast to produce 375,000 tons per year of low volatile metallurgical coal once fully operational. Coal production at the mine is anticipated to begin in the second quarter of 2017 and ramp up over the course of the year.

“Extreme global shortages of metallurgical coal have caused prices to increase 250% since earlier in the year,” said George
Dethlefsen, CEO of Corsa. “Corsa is taking steps to maximize
coal production and sales to capitalize on the favorable market environment.”

In September, development work commenced at the Acosta deep mine, he added.

Dethlefsen added that the company expects Corsa’s metallurgical coal sales volumes to increase by more than 70% in 2017 and be heavily weighted toward the higher-priced export market. A prolonged downturn in metallurgical coal prices over the past several years has left coal operators in a weakened position to respond quickly with new supply. With low metallurgical coal inventories globally, production difficulties in China and Australia, and signs of improvement in global steel pricing, Dethlefsen believes that metallurgical coal pricing will remain at elevated levels for an extended period of time.

Sunrise Gets Approval for Oaktown Mine Shaft

Sunrise Coal, a subsidiary of Hallador Energy LLC, will begin construction on a new $5 million mine shaft to reduce underground travel time for more than 100 employees of its Oaktown underground mining complex in Knox County, Indiana, to reach the working face. It received final approval in November from the Knox County Planning Commission.

Once the shaft is completed next year, it is expected to improve efficiency and safety, decreasing the company’s operating costs in the process. Not only will the new shaft near Bruceville cut the amount of time miners typically spend traveling underground to their job site, it also will lessen the amount of time needed to transport miners to a hospital. According to Sunrise, the new shaft should reduce transport times by about a half hour.

The planning commission’s decision did not come without opposition, however. Several residents near the proposed shaft said they were concerned about the prospect for increased traffic on the narrow roads in the area and asked the commission to deny Sunrise’s request.

Supporters of the project, including county economic development officials, stressed that coal mining is an important economic contributor to the southwestern Indiana county, accounting for more jobs than all other employers except for the local hospital. They feared a denial of the request could have affected the continued operation of the Oaktown Nos. 1 and 2 continuous miner operations, although the company never threatened to close the mines if its application was not approved.

The Oaktown mines produced about 4 million tons of steam coal in the first nine months of 2016 and are expected to produce in excess of 5 million tons for the entire year. Their combined 2015 output was 5.6 million tons and they have about 580 employees.

Hallador Sees Improvement in US Steam Coal Market

Hallador Energy Co., encouraged by improving signs in the U.S. steam coal market, expects the fourth quarter of 2016 to be its strongest this year in terms of sales as it looks to lock up additional tonnage for 2017 before the year draws to a close.

Brent Bilsland, president and CEO of the Terre Haute, Indiana-based parent company of Sunrise Coal, told analysts during a third-quarter earnings call in November that hot summer weather “brought a strong burn” to the domestic electric utility market on which Hallador focuses.

“We’re all a little surprised at how strong the domestic market has increased,” he observed. “If we see winter creep up, we’re going to see some strong demand in Indiana.”

“Natural gas prices have improved substantially and the export market has improved dramatically, to the point where now that Illinois Basin (ILB) coal is moving to export,” he continued. Bilsland said he has heard other ILB producers may be moving up to 3 million tons overseas. “It’s a great trend. We hope it continues,” he added.

Although Hallador’s core market will remain in the U.S., Bilsland said his company may sell some modest amounts of ILB coal overseas as well. “It would be in the hundreds of thousands” of tons, “not millions,” he said.

Hallador probably would ship the coal out of the Port of Baltimore in Maryland.

Despite a dip in third-quarter sales to just less than 1.5 million tons, compared to about 1.8 million tons a year earlier, Hallador still expects to wrap up 2016 with total sales of approximately 6.3 million tons. “We expect to see higher volumes in the fourth quarter,” he said. “We now expect Q4 to be our largest from a sales volume perspective, an increase of 17% over the third quarter and the average sales price to be $42.80/ton for Q4.”

So far, Hallador has lined up committed sales of 4.9 million tons for 2017 at an average price of $43.67/ton. However, several utility requests for proposals remained outstanding in November and Hallador fully expected to add to next year’s sales commitments. As a result, Bilsland forecast 2017 sales of 6 million to 6.5 million tons.

For the past year, the Carlisle underground mine in Sullivan County, Indiana, operated by Sunrise essentially has been idled because of market conditions. Carlisle once was Hallador’s flagship operation, mining 3 million tons per year.

According to Bilsland, bringing Carlisle back into production in 2017 is “something we’ve definitely considered.” But first, Hallador wants to see stronger sales “and prices strengthen a little more before we bring capacity back on line.” Nevertheless, “the trend certainly is in the right direction.”

At present, virtually all of Hallador’s production comes from its two Oaktown underground mines in Knox County that are operated by Sunrise. The mines were acquired from Vectren Fuels, a subsidiary of Evansville, Indiana-based Vectren Corp., in 2014. Hallador also gets a small amount of lower-sulfur coal from its Ace in the Hole surface mine in Clay County, Indiana.

Alliance Posts Record Sales for 3Q

Taking advantage of an improving steam coal market, Alliance Resource Partners posted record sales in the third quarter of 2016 while its earnings increased, and the Tulsa, Oklahoma-based company is preparing to ramp up production at its Hamilton No. 1 longwall mine in southern Illinois.

Alliance sold nearly 10.8 million tons of coal in the July-September period, its highest quarterly sales ever, and a 35.1% increase over second-quarter 2016 sales of 8 million tons. The third-quarter tonnage also was 4.5% higher than the 10.2 million tons the company sold in the third quarter of 2015.

Joseph Craft III, Alliance president and CEO, told analysts that his company is “beginning to see positive signs for the markets we serve.” Mostly, Alliance serves the U.S. electric utility market, though it also booked export sales of 3 million tons of steam coal over the next six months.

Typically, Alliance does not participate in the seaborne export market. “We prefer to market all our coal domestically,” Craft said. He added, however, “we could move more tons overseas. We contracted for 3 million tons to be sold in the fourth quarter this year and first quarter of 2017. Beyond that, we need to evaluate demand of the domestic market relative to the export market.” The destination for the exported coal was not disclosed.

Although production dipped to 8.5 million tons in the third quarter from 11.4 million tons a year ago, Alliance’s overall third-quarter performance encouraged the company to boost both its production and sales forecast for all of 2016. Alliance now expects to produce in the range of 34.5 million to 35.5 million tons and sell in a range of 36.5 million and 37 million tons this year.

In the latest quarter, Alliance secured 11.2 million tons of additional sales commitments through 2020. Currently, the company has sales commitments of 29.1 million tons, 17.4 million tons and 8.9 million tons for 2017, 2018 and 2019, respectively.

In response to a difficult market more than a year ago, Alliance idled its Onton and Gibson North underground mines in Hopkins County, Kentucky, and Gibson County, Indiana, respectively, and shifted production to lower-cost operations.

Despite what Alliance views as an improvement in the domestic steam coal market, Craft said his company has no immediate plans to restart production at any idled mines. “Even though the industry supply/demand balance is improving, we believe coal prices need to show more strength before we increase production,” he said. Until then, Alliance intends to match production to committed sales.

Alliance received a lower average price for its coal — $49.63/ton — in the third quarter than its average sales price of $53.18/ton in the second quarter of 2015.

Overall, Craft seemed optimistic about the direction the steam coal market is going in the U.S. “In the fourth quarter and beyond, assuming normal weather patterns, we expect improvement in the domestic coal market should continue as higher gas prices spur increased demand for coal,” he said.

With the improved supply/demand balance he believes will occur, Craft expects pricing to get better in the coming years as “certain mines will be mining out in the 2017-2018 time period. The forward pricing curve should continue to improve.”

Starting in November, Alliance plans to begin ramping up production at Hamilton No. 1, near McLeansboro in Hamilton County. Alliance acquired the mine more than a year ago from privately owned White Oak Resources.

“We’re going to try to ramp up to a 7.5 million tons a year runrate,” he said, adding the additional tonnage should displace lost volumes at Onton and the Pattiki underground mine in White County, Illinois, that Alliance also is shutting. Also, “we’ll probably reduce some western Kentucky production.” Hamilton No. 1 has produced around 2 million tons annually.

Minnesota Power Idling 2 Units at Boswell

One year after announcing plans to diversify its coal-heavy generation portfolio and confirming it would examine Units 1 and 2
at the Boswell coal-fired complex in Cohasset, the Allete subsidiary confirmed October 19 that it will retire those units by the
end of 2018.

Boswell Energy Center, Minnesota Power’s largest thermal generating facility, has a total of four generating units; 3 and 4 remain online at a combined capacity of 1,000 megawatts (MW). The latter of the two has been the focus of a $350 million environmental upgrade to reduce mercury, particulates and sulfur dioxide emissions.

Minnesota Power officials said the decision to close the units, which have a capacity of 65 MW each and employ a staff of 30, is in line with its EnergyForward plan.

“The decision to retire units 1 and 2 at Boswell, though difficult for our employees and host communities, is consistent with Minnesota Power’s EnergyForward strategy of diversifying its energy mix, reducing its carbon footprint and evolving away from smaller, older coal generators,” said Allete Chairman, President and CEO Alan Hodnik.

“Multimillion dollar investments in emissions reductions and new turbine rotors at Boswell units 3 and 4 in recent years have made them among the cleanest-operating, most highly efficient electric generators in the nation,” he said. “These large, state-of-the-art units, along with the company’s investments in renewable energy and access to low cost power markets, will ensure the continued availability of reliable and affordable electricity to meet the needs of all our customers, including those who compete in global markets.”

Josh Skelton, vice president of Minnesota Power generation operations, said the company is working to avoid furloughing the affected employees.

The Duluth-based utility first submitted its Integrated Resource Plan to the Minnesota Public Utilities Commission in late 2015. In it, Minnesota Power had proposed improvements to units 1 and 2 and keeping them operational through 2024. However, the company said, an analysis of usage projections and industry trends revealed that retiring the units was the best economic decision. Boswell units 1 and 2 are the last of Minnesota Power’s small coal-fired units to be retired, idled or converted to natural gas under the initiative.

Another Allete subsidiary is BNI Coal, which operates a 4.5-million-ton-per-year Center surface lignite complex in North Dakota that feeds two units at the neighboring Milton R. Young generating station. The company, which opened the Center in 1970, moved two of its draglines to Area C of the complex last year for further production.

Earlier this year, BNI gained a new parent company, BNI Energy, to pursue energy opportunities including carbon projects in North Dakota.

Luminant Closing Oak Hill Mine

Just one month after Westmoreland Coal cut 250 jobs with the closure of its Jewett operation, Luminant is closing its Oak Hill mine and sending another 132 Texas lignite workers to the unemployment line.

The furloughs will begin on December 16. Officials told local newspaper the Longview News-Journal that 28 administration workers are being cut along with 26 individuals each from three other mines that will remain in operation due to a collective bargaining agreement. While no exact impetus for the closure was disclosed, Westmoreland’s decision to close Jewett stemmed from a decision by customer NRG Energy to switch to cleaner burning Powder River Basin (PRB) coal from Wyoming.

Luminant has also been making an effort to shift to other sources for power generation; it purchased two Texas gas-fired facilities earlier this year. Three other Luminant coal mines — Winfield, Thermo and Monticello — have already been closed.

“This has been a very difficult decision, but one that is required to continue to run the business efficiently,” said Tim Bosecker, Martin Lake mines director, in a communication to the Texas Workforce Commission, according to the News-Journal. He added that Oak Hill’s closure will not impact production at the Martin Lake power plant; it will continue to run with both lignite and PRB tonnage.

The 26,000-acre surface site at Oak Hill will be reclaimed in a multiyear project.

Luminant is owned by Dallas-based Energy Future Holdings, which filed for bankruptcy protection in 2014.

Contura Seeking to Permit, Mine PA Reserves

Contura Energy, which took over core assets from Alpha Natural Resources following that company’s bankruptcy earlier this year, has entered applications to mine coal reserves in Greene County, Pennsylvania, at what was to be known as the Foundation mine.

In a notice published earlier this month in the Pennsylvania Bulletin, company affiliate Cumberland Contura formalized the ownership change for a previous permit by Alpha for the block in Holbrook.

In the notice, the company said the project will now be permitted as an expansion under the mining permit for its Cumberland operation. Specifically, the permit application encompasses 9,438 acres of coal in Center, Jackson and Richhill townships with the ultimate goal to longwall mine the reserves.

“These reserves were a part of the asset purchase Contura Energy completed in late July from Alpha Natural Resources and requesting a change in ownership permit is the next step in that process,” a Cumberland Contura spokesperson said. “Assuming the permitting process is completed for these reserves, any future mining activities would depend upon market conditions.”

The individual declined further comment, noting that any future mining decisions have not yet been made.

Pennsylvania Department of Environmental Protection spokesman John Poister said the permit application is now in the review stage and a final decision was likely several months away.

Paringa’s Detection of No. 11 Coal Seam Places it Closer to Becoming Top Producer

In what it described as a “game changer,” Paringa Resources Ltd. said in October the discovery of the western Kentucky No. 11 coal seam above the more prevalent No. 9 seam at its proposed Poplar Grove underground mine site in McLean County “significantly enhances” its goal of becoming a major coal producer in the Illinois Basin (ILB).

During the past two years, the Australian company has undergone several important changes in its mine development efforts in western Kentucky, which is part of the ILB. Foremost, perhaps, was flip-flopping the development order for the two deep mines it has been considering. Paringa decided earlier this year to first develop the Buck Creek No. 2 mine, recently renamed Poplar Grove, after additional engineering studies showed it could be brought into production far less expensively than its sister Buck Creek No. 1 mine.

Now, thanks to a newly completed core drilling program, Paringa has discovered the No. 11 seam containing an estimated 85 million to 110 million tons of high-quality ILB coal lies only 65 ft to 80 ft above the No. 9 seam at the mine site.

According to the company, the No. 11 seam averages about 5 ft thick with “clean coal quality characteristics” similar to the No. 9 seam product. The No. 11 seam coal has a heat content ranging from 12,000 Btu/lb to 12,200 Btu/lb, with sulfur content in the 3% range, ash around 7.4% and less than 9% moisture content.

Mining conditions for the No. 11 seam appear to be “excellent,” the company added, “with the immediate roof consisting of a black shale horizon overlain by an extremely competent limestone. In general, the WK No. 11 coal seam is about 1 ft thicker than the WK No. 9 coal seam in the Poplar Grove area.”

David Gay, Paringa president and CEO, said the No. 11 seam’s presence at Poplar Grove “significantly increases the capacity at Poplar Grove for minimal capex, truly transforms the mine and increases the strategic nature of the Buck Creek complex.”

WPS Anticipates More Electricity Will Come From Coal in 2017 Than 2016

Wisconsin Public Service Co. (WPS) expects to generate more electricity from burning steam coal in 2017 than in 2016, at least partly because of higher natural gas prices that are improving coal’s competitiveness with gas.

WPS, a subsidiary of Milwaukee-based WEC Energy Group, told the Wisconsin Public Service Commission in October its overall generation from coal is forecast to be 433,151 megawatt-hours higher in 2017. The utility’s coal-burning power plants include Edgewater, Columbia, Pulliam and Weston.

John Guntlisbergen, WEC’s manager of electric fuel cost recovery, said lower market prices for coal and higher market prices for natural gas are favoring an increased coal burn next year at Edgewater, near Sheboygan, Wisconsin.

Indeed, WPS, which largely burns low-sulfur coal from the Powder River Basin, expects to see a decrease of 3-7% from coal-fired generation in 2017 at Edgewater, Columbia and Pulliam.

Generation costs at Weston, near Wausau, Wisconsin, are projected to increase by about 5% in 2017 as a result of higher costs for chemicals needed to control emissions. But lower coal prices should offset those costs, Guntlisbergen said.

WPS is operating a new ReAct environmental control system at 321-megawatt Weston unit 3, accounting for the higher chemical costs. The Regenerative Activated Coke Technology is designed to reduce sulfur dioxide, nitrogen oxide and mercury emissions.

WPS’s natural gas generation, meanwhile, expected to decrease by about 787,817 megawatt-hours, or 34.1%, in 2017.

The 231.2-megawatt Pulliam station on the Fox River in downtown Green Bay, Wisconsin, is ticketed for retirement in the coming years.

WEC President and CEO Allen Leverett told analysts his company wants to shutter Pulliam as soon as it gets approval from the Midcontinent Independent System Operator, a regional grid operator in Carmel, Indiana. Pulliam’s two units began operating in 1958 and 1964, respectively.

While there is no specific timetable yet for Pulliam’s retirement, a WEC spokeswoman indicated it probably will be around 2020.

WVDEP, Alpha Natural Resources Reach $15 Million Settlement

The West Virginia Department of Environmental Protection (DEP) has reached an agreement with Alpha Natural Resources valued at about $15 million to resolve a recently filed lawsuit in the coal operator’s bankruptcy case. The settlement enhances DEP’s earlier settlement with Alpha and will provide additional bonding and other security for the coal operator’s ongoing reclamation obligations in West Virginia.

Under the earlier settlement, announced in June, Alpha
has posted bonds and other collateral totaling nearly $140 million with respect to its remaining mining sites in West Virginia. Alpha and Contura Energy Inc., which purchased a substantial amount of Alpha assets in July, have also committed to provide at least $165 million to fund reclamation and water treatment in West Virginia.

In early November, five months after that agreement was finalized, Alpha announced a $100 million error in the financial projections underlying its bankruptcy plan, which included the DEP settlement. The company simultaneously announced a new proposed settlement with Contura Energy and its former secured creditors that partially reduced that gap. However, DEP remained concerned about the effects of Alpha’s reduced cash flow projections and brought suit in Alpha’s bankruptcy case.

Under the settlement, DEP has agreed to dismiss the complaint and release the defendants from liability relating to the error in the financial projections. In exchange, Alpha agreed to post its Julian headquarters building, which recently appraised for $6.3 million, as collateral securing its remaining reclamation obligations in West Virginia.

In addition, Contura agreed to post a $4 million letter of credit and issue a secured $4.5 million guaranty of Alpha’s obligations, each through the end of 2018. By that time, Alpha expects its financial condition to return to the level projected in its prior bankruptcy projections.

Plans to Retire More Indiana Coal-burning Power Plants

Two more major Indiana electric utilities, Northern Indiana Public Service Co. and Vectren Corp., have unveiled tentative plans to retire several coal-burning power plants in less than a decade in an attempt to diversify their generation fleets in an era of flat load growth, low natural gas prices and costly environmental regulations.

Together, Nipsco and Vectren expect to shutter about 2,000 megawatts (MW) of coal-fueled generation — Nipsco roughly 1,200 MW by the end of 2023, Vectren approximately 800 MW by the close of 2024, according to their newly released integrated resource plans. The 20-year plans are required by the Indiana Utility Regulatory Commission to be filed every two years, and the latest documents are the first time the two utilities have seriously evaluated closing baseload coal plants.

Nipsco, a Merrillville-based subsidiary of NiSource Inc., said it intends to retire its 480-MW Bailly coal plant as early as mid-2018, with two units representing 722 MW at its 1,780-MW R.M. Schahfer coal plant retiring by the close of 2023.

Vectren, with headquarters in Evansville, said its “preferred” plan is to retire the 650-MW A.B. Brown coal plant, part of its Culley coal plant, and withdraw co-ownership in Alcoa’s Warrick coal plant by 2024.

“We’ve identified a preferred path that provides customer and environmental benefits, reflective of our goal to focus on providing affordable, clean energy while maintaining flexibility for future technology and market changes,” said Nipsco President Violet Sistovaris. Nipsco analyzed a range of options for its existing, heavily coal-reliant 3,800-MW generating fleet while evaluating the “unique impacts on customer costs, environmental compliance, communities and workforce needs,” she added.

For the coal units Nipsco does not intend to retire, including its 580-MW Michigan City generating station and the remaining units at Schahfer, the utility plans to move forward with required environmental compliance filings consistent with results indicated in the IRP.

In the short term, after closing Bailly in about two years, Nipsco will rely primarily on existing resources through 2019, but may need to purchase power from the market to fill in any gaps.

For its proposed coal retirement decision, Vectren specifically cited a slate of federal mandates, including the Coal Combustion Residual rule that provides guidelines on coal ash handling and disposal regulations around the use of ash ponds and the Effluent Limitations Guideline that includes more stringent limits on wastewater discharges from coal plants.

Vectren’s decision is not officially a done deal, as the utility plans over the next several months to “finalize our generation plan with steadfast consideration for customer bill impacts,” said Carl Chapman, the company’s chairman, president and CEO. “To speculate on exactly what that will look like and the timing is premature, but it will likely include natural gas and renewable energy options, as well as our continued offering of energy efficiency programs to ensure customers are focused on using energy wisely.”

According to Vectren spokeswoman Natalie Hedde, it is likely 270-MW Unit 3 at the Culley plant in Warrick County will be the utility’s only coal-fired generator beyond 2024. Vectren does not want to retire all of its coal generation, she said, because it does not want to rely exclusively on only one resource, be it natural gas, renewables or coal.

The decisions to retire coal generation are expected to have a significant impact on future coal purchases by both Nipsco and Vectren. Nipsco typically burns between 6 million and 7 million tons of coal annually, mostly from the low-sulfur Powder River Basin, high-sulfur Illinois Basin (ILB) and Northern Appalachia. Vectren burns around 4 million tons of high-sulfur coal a year, exclusively from the ILB.

During the past year, Duke Energy Indiana, the state’s largest electric utility, retired its 668-MW Wabash River coal-burning generating station while Indianapolis Power & Light closed its 341-MW Eagle River coal plant and converted its 700-MW Harding Street coal plant in downtown Indianapolis to natural gas.

In 2015, Indiana Michigan Power Co., a subsidiary of Ohio-based American Electric Power Co., shuttered its 995-MW Tanners Creek coal plant.

Rhino Sells Out Current Capacity for 2017

The recent rally in coal prices, particularly in the global metallurgical coal market, enabled Rhino Resource Partners to book additional coal sales for the remainder of 2016 and fully sell out its current steam and met coal production capacity for its Central Appalachia (CAPP) operations for 2017.

Joe Funk, CEO of the Lexington, Kentucky-based company, said in a November third-quarter 2016 earnings report that Rhino may add additional production capacity for 2017 in CAPP “if we can obtain coal sales at prices that justify the capital expansion dollars required to increase our production capabilities.”

In the October-December period of 2016, Rhino had total committed sales of 868,940 tons at an average price of $49.74/ton. That includes CAPP sales of 260,540 tons at an average price of $59.20/ton. However, in 2017 the company has locked in CAPP sales of 1.1 million tons at a higher average price of $68.73/ton.

Rhino sold 843,000 tons in the third quarter, up from 836,000 tons a year earlier, including 402,500 tons in Northern Appalachia (NAPP) and the Illinois Basin (ILB), and 205,900 tons at its Rhino Western operations in Utah at average prices of $47.95/ton and $38.72/ton, respectively.

In 2017, Rhino has total sales commitments so far of 3.57 million tons, including 1.71 million tons in NAPP/ILB and 700,000 tons at Rhino Western.

“All of our Central Appalachia mining complexes were in operation during the third quarter as the upturn in the global met market allowed us to secure sales for the remainder of 2016 and we have fully sold our current steam and met coal production capacity at our Central Appalachia operations for 2017,” Funk said.

Rhino recently landed a sales contract for about 500,000 tons from November 2016 through December 2017 for its Hopedale underground mine in Harrison County, Ohio, according to Funk. “We continue to seek additional sales contracts for Hopedale to bring it to full production capacity for 2017,” he said.

The Pennyrile underground steam coal mine in McLean County, Kentucky, continues to be a bright spot for Rhino. The company’s newest major continuous miner operation has achieved productivity gains that lowered production costs, improved coal recovery rates and turned the mine into a “positive cash flow producer during the first nine months of 2016,” Funk said.

Pennyrile, also known as Riveredge, is fully contracted for 2017 at current production levels of 1.3 million tons annually. The mine has term contracts with Louisville Gas & Electric Co. and Big Rivers Electric Corp., a Henderson, Kentucky-based generation and transmission co-op.

Rhino trimmed its losses in the third quarter to $3.7 million, from $9.3 million a year ago. The company recorded total revenue of $43.4 million in the latest quarter, down from $51.8 million in the third quarter of 2015. Coal revenue was $40.9 million, compared to $45.4 million a year earlier.

Armstrong Secures Additional Coal Sales

Armstrong Energy Co., the St. Louis-based parent company of Armstrong Coal, was successful in the third quarter of 2016 in securing additional steam coal sales of approximately 300,000 tons for delivery before the end of 2016.

The extra business — Armstrong did not disclose the buyer — raised to 5.9 million tons the amount of high-sulfur coal the company essentially has fully priced and committed for the year.

Marty Wilson, Armstrong Energy president and CEO, told analysts that Armstrong has 5 million tons of coal priced and committed for 2017. Discussions are ongoing with customers about adding more tons, he said, so the final 2017 figure could be higher.

In addition, Wilson said the company’s uncommitted tonnage in 2017 could be anywhere between 300,000 tons and 900,000 tons. However, “we don’t feel it will be 900,000 tons. We’ll be able to turn some options into committed tons,” he added.

Armstrong was able to book additional tons because the hot summer helped to burn down inventories at some electric utilities, he said. “Pricing has picked up on the spot market but it is still relatively low because there is plenty of supply and still inventory,” he added. “We’re seeing in some basins there’s a little bit more of a movement in pricing. In the Illinois Basin (ILB), it’s more of a modest increase.”

While Armstrong still predicts a recovery in pricing, hopefully in 2017, Wilson said many utilities still are concerned about committing to long-term contracts, given the volatility of natural gas prices and government regulations. “We continue to say that weather and natural gas prices are the key drivers of any pickup in demand,” Wilson said. “We believe relatively continued high inventory levels in the shoulder season will delay a more complete recovery until late 2017 or early 2018.”

Although coal output in the ILB was projected by Armstrong to total around 99 million tons in 2016, down about 25 million tons from 2015, Wilson said the basin’s production could bounce back to 115 million tons in 2017. That’s partly because of stronger export sales.

The company finally closed its Parkway underground mine near Central City in Muhlenberg County this fall. Parkway had remained in production a few months longer than expected.

Armstrong posted a net loss of $9.7 million on revenue of $65.3 million in the third quarter. That compared to a net loss
of $145.7 million on revenue of $89.2 million in the third quarter of 2015.