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Thursday, October 1, 2015

ENERGY TRADER

www.platts.com ELECTRIC POWER

Key daily indexesHub/Delivery point Index Change

electricity ($/MWh)

PJM Western Hub 36.26 -2.80ISONE Internal Hub 24.40 -6.41Into Southern 30.00 1.50MISO Indiana Hub 32.31 1.01ERCOT North Hub 25.67 -2.09Palo Verde 27.94 -1.96

Gas ($/MMBtu)

TX.Eastern, M3 1.345 0.000Algonquin, city-gates 1.905 -0.150Chicago city-gates 2.570 -0.080Henry Hub 2.475 -0.055SoCal Gas 2.530 -0.100

nyMex futures

Henry Hub gas ($/MMBtu) 2.524 -0.062

FORECAST Changes in natural gas production, storage, weather and customer demand are likely to keep this winter’s natural gas prices flat compared to last year, the Natural Gas Supply Association said Wednesday in its winter outlook.

The combined factors are likely to “place neutral pressure” on winter 2014-15 prices, compared with last winter when Henry Hub prices averaged $3.21/MMBtu, NGSA said.

Slightly lower demand this winter will be balanced by a rise in domestic production levels, partially offset by lower net imports, according to an analysis prepared for the group by Energy Ventures Analysis. The net effect should be storage withdrawals of about 1.1 Bcf/d less than last winter, EVA said.

NGSA emphasized strong natural gas production and storage inventories approaching a new record.

“The picture that emerged for the upcoming winter is one of a flexible natural gas market that is able to respond to changes in weather and customer demand with abundant production and storage,” said Bill Green, chairman of NGSA and vice president of

‘neutral pressure’ seen on gas winter prices

(continued on page 17)

ANALYSIS As Hurricane Joaquin continued to rumble toward the Eastern Seaboard on Wednesday, industry players were left to ponder what impact the storm might have on natural gas production, demand and pricing.

The energy sector fallout from Superstorm Sandy in 2012 was seen as providing some context.

Sandy, which followed a path along the coast similar to what has been seen so far with Joaquin, created a slight, temporary decrease in Northeast gas production along with a minimal dip in demand. It also had a slight effect on prices, causing December gas futures at NYMEX to drop 11.2 cents when the storm made landfall on October 29, 2012.

Prices quickly rebounded though and topped $4/MMBtu at Transco Z6 NY just a week later.

Much of Sandy’s impact was felt on the power grid, leaving more than 8 million people without electricity for varying lengths of time. The storm’s effects on New York State’s power lingered well into November, according to New York Independent System Operator’s Ken Klapp, who was working in the heart of the storm at the time.

“The devastating effects of Superstorm Sandy included extensive, extended power outages in the New York metropolitan region and prompted significant scrutiny of electric utilities and an increased focus on the resilience of the power grid,” Klapp said.

The 2012 storm produced power outages affecting more than 2

Joaquin may follow superstorm sandy’s path


The NYMEX November natural gas futures contract settled Wednesday at $2.524/MMBtu, down 6.2 cents, as traders focused on the possibility of milder weather and weakening demand in the coming weeks.

The contract settled lower for a second-straight day after giving up 8.4 cents Tuesday.

Tom Saal, broker at INTL FC Stone, attributed Wednesday’s movement to the November contract trying to get back in line with October’s expiration, which was at $2.563/MMBtu Monday. “We got a big storage number probably coming out tomorrow, probably triple digits, which reflects the lack of demand,” he said.

“Now we are right back in the old range and will hang here until the next data comes out, which will be the storage report. Nothing from the tech standpoint has changed — still a rangebound trade with a distinctly bearish bias,” EcomEnergy said in its Daily Call email.

The US Energy Information Administration is expected Thursday to estimate a gas storage injection between 98 Bcf and 102 Bcf for the reporting week ended Friday, according to a consensus of analysts that Platts surveyed.

A build within that range would be below the 110-Bcf injection reported at the same time a year ago, but above the 94-Bcf five-year average build.

According to the National Hurricane Center advisory issued Wednesday morning, Hurricane Joaquin has strengthened as it moves southwest toward the central Bahamas. The NHC five-day track showed the storm heading northwest to the US East Coast.

“Forecasts of early heating demand are no more. What was once supposed to be a cold start to the month is now awash with warm air and water from the Caribbean,” said Gelber & Associates Aaron Calder in an email.

november gas futures down 6.2 cents

natural Gas Futures CoMMentary

natural Gas

Thursday, OcTOber 1, 2015energy Trader

2Copyright © 2015 McGraw Hill Financial

SoutheaSt day-ahead bilateral indexeS for oct 1 ($/MWh) Avg Marginal Index Change $/Mo heat rate

southeast on-peak

VACAR 30.50 -0.25 30.50 12176Southern, Into 30.00 1.50 30.00 12270GTC, Into 30.50 1.50 30.50 10225Florida 36.00 1.50 36.00 13187TVA, Into 29.00 1.50 29.00 11682

southeast off-Peak

VACAR 23.50 2.00 23.50 9381Southern, Into 24.00 4.50 24.00 9816GTC, Into 25.00 5.00 25.00 10225Florida 28.25 4.50 28.25 10348TVA, Into 22.75 2.75 22.75 9164

day-ahead electric lMP MarketS for oct 1 ($/MWh) Avg MarginalHub/Zone Average Cong Loss Change $/Mo heat rate

ISONE on-peak

Internal Hub 24.40 0.00 -0.03 -6.41 24.40 12157

ISONE off-Peak

Internal Hub 18.53 0.01 0.00 -3.12 18.53 8910

NYISO on-peak

Hudson Valley Zone 27.96 0.00 2.59 -3.42 27.96 11478N.Y.C. Zone 28.61 -0.47 2.77 -3.71 28.61 11745West Zone 25.75 -0.12 0.27 -3.12 25.75 15000

NYISO off-Peak

Hudson Valley Zone 17.46 -0.18 1.55 -0.66 17.46 7599N.Y.C. Zone 17.68 -0.18 1.77 -0.67 17.68 7695West Zone 15.90 0.00 0.18 -0.48 15.90 8880

PJM on-Peak

Western Hub 36.26 2.53 0.64 -2.80 36.26 22721Dominion Hub 34.55 1.39 0.08 -0.88 34.55 14243Eastern Hub 52.52 17.72 1.71 -6.00 52.52 28327

PJM off-Peak

Western Hub 23.17 0.27 0.32 -0.72 23.17 14299Dominion Hub 23.38 0.69 0.11 -0.24 23.38 9550Eastern Hub 41.49 17.91 1.00 -2.00 41.49 24337

near-terM MarketS ($/MWh)Contract transacted range

southern, into

Bal-week 09/29 26.25-26.75Bal-week 09/25 28.25-28.75Next-week 09/25 27.75-28.25Next-week 09/24 27.75-28.25

Generation unit outaGe rePortPlant/operator Cap Fuel state status return shut

east

Atikokan/OPG 205 bio Ont. MO Unk 09/29/15Beaver Vly-2/FirstEnergy 943 n Penn. RF Unk 09/26/15Bowen-2/Georgia Power 800 c Ga. PMO Unk 04/04/13Darlington-1/OPD 881 n Ont. MO Unk 09/14/15Darlington-2/OPD 881 n Ont. MO Unk 09/14/15Darlington-3/OPD 876 n Ont. MO Unk 09/11/15Darlington-4/OPD 881 n Ont. MO Unk 09/14/15Goreway-11/SitheGoreway 195 g Ont. MO Unk 09/18/15Hope Creek-1/PSEG 1240 n N.J. MO Unk 09/28/18Lake Superior/Brookfield 120 g Ont. PMO Unk 11/04/14Lennox-3/OPG 525 g Ont. MO Unk 09/04/15Lennox-4/OPG 525 g Ont. PMO Unk 09/28/15McGruire-2/Duke 1156 n N.C. MO Unk 09/12/15Peach Bottom-3/Exelon 1182 n Penn. PMO Unk 09/21/15Pickering-6/OPG 520 n Ont. MO Unk 09/21/15Saint Lucie-2/FP&L 1002 n Fla. MO Unk 09/07/15Vogtle-1/Southern Nuclear 1205 n Ga. RF Unk 09/20/15WattsBar-1/TVA 1210 n Tenn. PMO Unk 09/20/15

east PoWer MarKets

Mass Hub tumbles to upper $20s/MWhWeaker spot natural gas and slipping demand pressured Northeast dailies Wednesday.

Mass Hub on-peak prices for Thursday delivery plummeted $7.25 to below $28.75/MWh on the IntercontinentalExchange. Mass Hub day-ahead off-peak fell $6.25 below the previous settlement to $18/MWh.

The ISO New England predicted peakload at 15,800 MW Thursday, nearly 2,000 MW below Wednesday, but about 300 MW above the average peakload October 2014.

Algonquin Gas Transmission city-gates spot gas declined 22.5 cents to $1.830/MMBtu.

Boston temperatures were forecast to drop from a high of 70 degrees Wednesday to highs in the mid-50s Thursday and Friday, more than 10 degrees below normal.

Day-ahead locational marginal prices across New York fell with demand midweek.

New York ISO Zone G Hudson Valley day-ahead on-peak LMPs lost $3.50 to below $28/MWh for Thursday delivery, while Zone J New York City day-ahead on-peak dropped $3.75 to about $28.50/MWh. Zone A West day-ahead on-peak slipped $3 to $25.75/MWH, roughly $14 below spot prices seen October 2014.

Transco Zone 6 New York spot natural gas climbed 43.1 cents to $2.446/MMBtu; however, this did not appear to support prices.

The New York ISO predicted peakload near 20,700 MW Wednesday, 19,200 MW Thursday and 18,700 MW Friday. Peakload averaged about 19,125 MW this time last year.

Northeast power terms dropped Wednesday afternoon amid mixed regional gas basis and lower NYMEX gas futures.

In New England, Mass Hub on-peak November sank $2.50 to below $53.25/MWh on the IntercontinentalExchange around 2:30 pm EDT. Mass Hub on-peak December was $69/MWh, $2.50 under the previous settlement and nearly $60 below October 2014 contract levels. The on-peak January-February winter package shed $2.25 to about $87.50/MWh.

In New York, Zone G on-peak November fell 75 cents to $44.75/MWh on ICE.

NYMEX November gas futures declined 6.2 cents to $2.524/MMBtu. Algonquin city-gate November gas basis gave up 19 cents to $2.470/MMBtu, while Transco Zone 6 NY November gas basis tacked on 11.9 cents to 18.9 cents/MMBtu.

Mid-Atlantic dailies fell Wednesday amid lower demand projections and stable spot natural gas.

PJM West Hub day-ahead on-peak dropped $1.50 to roughly $34.50/MWh for Thursday delivery on the IntercontinentalExchange. PJM day-ahead off-peak was around $22/MWh slipping $2.25.

The PJM Interconnection forecast peakload to slip from about 98,075 Wednesday to near 88,975 MW Thursday and 86,550 MW Wednesday, however this did not appear to weigh on prices.

Texas Eastern M-3 day-ahead natural gas eased 1.1 cents to $1.334/MMBtu.

Temperatures in the PJM Interconnection eastern region were forecast 5 to 15 degrees below average Thursday and Friday, with highs




daily sPot Gas PriCes, oCt 8 ($/MMBtu) Midpoint +/- absolute Common Vol. deals

northeastAlgonquin, receipts --- --- ------- ------- --- ---Algonquin, city-gates 2.330 -0.440 2.250-2.630 2.250-2.425 159 26Columbia Gas, App. 2.275 +0.000 2.240-2.340 2.250-2.300 201 41Columbia Gas, App. non-IPP --- --- ------- ------- --- --- Dominion, North Point 0.895 -0.090 0.880-0.920 0.885-0.905 31 10Dominion, South Point 0.915 -0.065 0.895-0.950 0.900-0.930 263 55Dracut, Mass. --- --- ------- ------- --- ---Iroquois, receipts 2.600 -0.080 2.510-2.640 2.570-2.635 84 18Iroquois, zone 2 2.640 -0.080 2.550-2.680 2.610-2.675 26 10Lebanon Hub 2.395 +0.010 2.390-2.400 2.395-2.400 51 4Leidy Hub 1.050 -0.190 1.050-1.050 1.050-1.050 5 1Millennium, East receipts 0.860 -0.060 0.850-1.050 0.850-0.910 70 9Niagara 1.300 -0.050 1.300-1.300 1.300-1.300 15 1REX, Clarington Ohio --- --- ------- ------- --- ---Tennessee, zone 6 del. 2.265 -0.370 2.100-2.500 2.165-2.365 93 20Tennessee, z6 (300 leg) del. --- --- ------- ------- --- ---Tennessee, zone 4-Ohio --- --- ------- ------- --- ---Tennessee, zone 4-200 leg 1.255 +0.045 1.230-1.270 1.245-1.265 177 27Tennessee, zone 4-300 leg 0.780 -0.030 0.700-0.890 0.735-0.830 95 27Tennessee, zone 4-313 pool 1.025 -0.075 0.920-1.110 0.980-1.075 50 10Tx. Eastern, M-2 receipts 0.870 -0.090 0.800-0.940 0.835-0.905 302 51Tx. Eastern, M-3 0.945 -0.105 0.890-0.970 0.925-0.965 189 39Transco, zone 6 non-N.Y. 2.320 -0.130 2.280-2.370 2.300-2.345 130 38Transco, zone 6 non-N.Y. North 2.325 -0.115 2.280-2.370 2.305-2.350 83 22Transco, zone 6 non-N.Y. South 2.310 -0.155 2.280-2.350 2.295-2.330 47 16 Transco, zone 6 N.Y. 2.320 -0.130 2.250-2.380 2.290-2.355 90 17Transco, Leidy Line receipts 0.835 -0.035 0.760-0.900 0.800-0.870 58 17

Gulf CoastColumbia Gulf, La. 2.370 -0.005 2.340-2.385 2.360-2.380 48 11Columbia Gulf, mainline 2.355 -0.010 2.300-2.375 2.335-2.375 407 61Florida Gas, zone 1 2.410 -0.005 2.410-2.410 2.410-2.410 12 1Florida Gas, zone 2 2.420 +0.005 2.400-2.425 2.415-2.425 208 9Florida Gas, zone 3 2.425 -0.025 2.390-2.440 2.415-2.440 159 15Florida city-gates --- --- ------- ------- --- ---Southern Natural, La. 2.385 -0.025 2.375-2.410 2.375-2.395 176 29Tennessee, zone 0 2.340 -0.030 2.320-2.450 2.320-2.375 104 19Tennessee, 500 leg 2.380 -0.040 2.370-2.400 2.375-2.390 123 27Tennessee, 800 leg 2.390 -0.015 2.360-2.400 2.380-2.400 149 18Tx. Eastern, ETX 2.380 +0.030 2.370-2.380 2.380-2.380 5 2Tx. Eastern, STX 2.400 -0.010 2.380-2.420 2.390-2.410 110 18Tx. Eastern, WLA 2.405 -0.025 2.350-2.425 2.385-2.425 126 13Tx. Eastern, ELA 2.340 -0.050 2.260-2.390 2.310-2.375 79 18Tx. Eastern, M-1 24-in. --- --- ------- ------- --- ---Tx. Eastern, M-1 30-in. 2.255 -0.105 2.250-2.290 2.250-2.265 1 3Transco, zone 1 2.375 -0.040 2.350-2.380 2.370-2.380 23 5Transco, zone 2 2.390 -0.025 2.390-2.390 2.390-2.390 2 2Transco, zone 3 2.410 -0.005 2.380-2.450 2.395-2.430 115 25Transco, zone 4 2.415 -0.030 2.380-2.450 2.400-2.435 251 38Transco, zone 5 del. 2.480 -0.025 2.450-2.505 2.465-2.495 60 18

Platts oil PriCes, seP 30 ($/b) ($/MMBtu)Gulf Coast spot1% Resid (1) 34.32-34.34 5.493% Resid (1) 33.82-33.84 5.41Crude spotWTI (Nov) (2) 45.16-45.18 7.79new york spotNo.2 (1) 60.45-60.49 9.680.3% Resid LP (3) 42.15-42.17 6.750.3% Resid HP (3) 40.65-40.67 6.510.7% Resid (3) 35.00-35.02 5.601% Resid (3) 34.65-34.67 5.551= barge delivery; 2= pipeline delivery; 3= cargo delivery

Platts enerGy trader sParK sPreads, seP 30 ($/MWh) new england Mid-atlantic southern

Median Change Peak Change Median Change Peak Change Median Change Peak ChangeGas 3.18 -5.58 -4.04 -5.30 15.63 -2.40 6.00 -2.20 3.06 2.00 -4.38 2.13Oil -60.03 -7.61 -93.44 -8.09 -57.94 -4.14 -75.91 -4.40 -62.64 0.18 -84.11 -0.13Coal -4.32 -6.41 10.72 -2.80 4.36 -2.80 6.94 1.50Nuclear 19.67 -6.41 31.24 -2.80 24.84 1.50

Platts Energy Trader spark spreads are the differences between on-peak spot electricity prices and spot fuel prices in a region calculated at two heat rates. A positive number shows the cost advantage (in $/MWh) of using that fuel to generate electricity; a negative number shows it is more economical to purchase power. The median heat rate is a composite of generating units using that fuel in each region. The peak heat rate is based on the least efficient 25% of generating plants.

east Gas MarKets

spot prices mixed on weather, constraintsSpot natural gas prices in the Gulf Coast fell Wednesday on seasonable weather in the region and decreased demand expectations.

Demand in the Southeast region is forecast to fall by nearly 300 MMcf/d to about 15.9 Bcf/d, according to Platts unit Bentek Energy. Texas demand is expected to hold about flat at 10.7 Bcf/d.

The spot price at Henry Hub shed 5 cents.Katy Hub edged a couple of cents lower while Tennessee Gas

Pipeline’s Zone 0 slipped about 5 cents. Houston is forecast to be in the high 80s Thursday, right around seasonal norms.

Southern Natural fell a little more than 5 cents each as New Orleans is forecast to be around normal in the mid-80s Thursday.

Transco Zone 3 and Zone 4 declined about 5 cents as Orlando is forecast to be around 90 Thursday, a couple of degrees above normal.

Spot prices in the Northeast were mixed on cooler-than-normal weather expected in the region and pipeline constraints.

Algonquin Gas Transmission city-gate saw the cash price drop about 15 cents on flow restrictions. According to a company website posting, AGT has approved and scheduled nominations at each pipeline segment and meter station up to AGT’s operational capacity. Constraints on the pipeline weighed on cash prices at its delivery points.

Tennessee Gas Pipeline’s Zone 6 200 Leg shed about 7 cents as Boston is forecast to be about 7 degrees below normal, with Thursday in the high 50s.

Temperatures in New York City are forecast to be 10 degrees below seasonal norms Thursday, with lows falling into the 40s. Residential, commercial and industrial demand is expected to jump nearly 1.3 Bcf/d to about 8.3 Bcf/d, according to Bentek data.

Transcontinental Gas Pipeline’s Zone 6 New York and Non-New York points tacked on around 40 cents.

In Appalachia, Dominion North and South shed a few cents each.



day-ahead electric lMP MarketS for oct 1 ($/MWh) avg Marginal

Hub/Zone average Cong loss Change $/Mo heat rate

Miso on-peakIndiana Hub 32.31 4.04 0.66 1.01 32.31 17477Michigan Hub 30.92 2.22 1.08 -0.12 30.92 10978Minnesota Hub 23.05 -2.75 -1.82 -2.43 23.05 8874Illinois Hub 33.25 5.76 -0.13 -3.85 33.25 12634Arkansas Hub 25.93 -0.56 -1.13 -2.02 25.93 10757Louisiana Hub 28.67 0.75 0.30 -1.55 28.67 11736Texas Hub 32.79 4.88 0.29 0.99 32.79 13043

Miso off-PeakIndiana Hub 18.44 0.72 0.55 -3.50 18.44 9833Michigan Hub 19.21 1.43 0.61 -2.26 19.21 6711Minnesota Hub 10.10 -5.60 -1.47 -4.70 10.10 3825Illinois Hub 18.32 1.08 0.06 -2.34 18.32 6804Arkansas Hub 19.57 2.88 -0.48 -0.56 19.57 8019Louisiana Hub 20.00 2.70 0.13 -0.83 20.00 8095Texas Hub 20.28 2.84 0.26 -0.53 20.28 8053

PJM on-peakAEP-Dayton Hub 29.66 -2.55 -0.88 -0.66 29.66 13733Northern Illinois Hub 27.97 -3.16 -1.96 0.18 27.97 10831

PJM off-PeakAEP-Dayton Hub 21.66 -0.48 -0.44 -0.68 21.66 9831Northern Illinois Hub 20.40 -0.81 -1.37 -0.93 20.40 7719

sPP on-peakSPP North Hub 17.09 -3.95 -1.68 -2.38 17.09 6743SPP South Hub 26.72 2.87 1.12 -1.58 26.72 11310

sPP off-PeakSPP North Hub 13.13 -1.67 -1.34 -1.30 13.13 5111SPP South Hub 19.62 2.84 0.63 0.15 19.62 8086


Central

Arkansas-2/Entergy 1065 n Ark. RF Unk 09/20/15Big Brown/Luminant 575 c Texas MO Unk 04/13/15Byron-1/Exelon 1242 n Ill. MO Unk 09/13/15Fermi-2/DTE 1131 n Mich. MO Unk 09/13/15Limestone-2/NRG 860 c Texas MO Unk 08/09/14Martin Lake-2/Luminant 750 c Texas MO Unk 02/01/15Martin Lake-3/Luminant 750 c Texas MO Unk 06/18/15Monticello-1/Luminant 565 c Texas MO Unk 06/18/15Monticello-2/Luminant 565 c Texas MO Unk 06/11/14Palisades/NMC 810 n Mich. MO Unk 09/15/15

day-ahead electric lMP MarketS for oct 1 ($/MWh) avg Marginal

Hub/Zone average Change $/Mo heat rate

erCot on-peakHouston Hub 28.29 0.60 28.29 11255North Hub 25.67 -2.09 25.67 10645South Hub 27.16 -0.79 27.16 11126West Hub 26.22 -1.94 26.22 11046

erCot off-peakHouston Hub 18.09 0.58 18.09 7184North Hub 18.02 0.52 18.02 7344South Hub 18.10 0.52 18.10 7335West Hub 18.04 0.50 18.04 7428

Central PoWer MarKets

indiana Hub falls to high $20s/MWhMidcontinent dailies were pressured by lower demand projections Wednesday as Electric Reliability Council of Texas dailies fell on lower demand expectations.

Indiana Hub day-ahead on-peak retreated over $2.50 to $29.50/MWh for Thursday delivery, while day-ahead off-peak lost $2 to about $19/MWh. On-peak spot prices averaged around $38/MWh this time last year.

The Midcontinent ISO predicted demand to peak near 81,875 MW Wednesday, 79,325 MW Thursday and 75,050 MW Friday. Peakload hit a high of 88,095 MW and averaged about 78,625 MW in October 2014.

Indianapolis temperature highs were forecast in the mid-60s Thursday and Friday, about 5 degrees below the norm.

Dailies in the Midwestern portion of PJM were lower amid weakness in nearby markets.

AD Hub day-ahead on-peak prices for Thursday delivery gave up $1.75 to $30.50/MWh. NI Hub day-ahead on-peak sank $3.75 to below $27/MWh, while day-ahead off-peak was $2.50 under the previous day at $19/MWh.

Midwest forwards were down amid weakness in nearby markets.AD Hub and NI Hub on-peak November financial futures both lost 25

cents to around $36.25/MWh and $33/MWh on ICE, respectively.Electric Reliability Council of Texas dailies were down Wednesday

with falling demand expectations.ERCOT North Hub day-ahead on-peak physical shed $1.50 to $26.50/

MWh for Thursday delivery on the IntercontinentalExchange and traded 300 MW, compared with 550 MW traded Tuesday. Off-peak financial traded 350 MW and cleared 1,250 MW at $17.50/MWh, down 50 cents. North Hub real-time on-peak averaged about $31.75/MWh Wednesday, up $2 from earlier in the day, and traded 5,400 MW, compared with 3,650 MW traded Tuesday.

Balance-of-the-day on-peak for Wednesday averaged $26.25/MWh, down $1.75 from where the daily package traded Tuesday, and traded 4,500 MW and cleared 550 MW, compared with 1,550 MW traded and 300 MW cleared Tuesday.

ERCOT North Hub balance-of-the-week on-peak lost $2.25 to $24.75/MWh. Next-week on-peak fell 25 cents to around $27.50/MWh.

Spot natural gas at Houston Ship Channel added 1.1 cent to about $2.531/MMBtu on ICE.

ERCOT forecast system load to peak at 56,550 MW Wednesday, 54,175 MW Thursday and 46,775 MW Friday. The North DC Tie was exporting 153 MW while the East DC Tie was exporting 598 MW, around 3 pm CDT Wednesday, with wind output at 973 MW. Wind generation was forecast to peak at 5,950 MW at 10 pm CDT Thursday.

High temperatures across Texas were forecast in the low to mid-80s to low 90s Thursday, as much as 5 degrees above normal. Low temperatures were expected in the upper 60s to low 70s, as much as 6 degrees above normal.

Real-time prices showed congestion Wednesday as the West Load Zone averaged $51/MWh for on-peak hours through 3 pm CDT after spiking as high as $253.26/MWh at 12:15 pm after wind





upper Midwest

Alliance, into interstates 2.500 -0.060 2.460-2.520 2.485-2.515 55 10ANR, ML7 2.540 -0.065 2.500-2.610 2.515-2.570 17 2Chicago city-gates 2.445 -0.015 2.350-2.510 2.405-2.485 632 108Chicago-Nicor 2.240 -1.000 2.140-2.310 2.200-2.270 2 5Chicago-NIPSCO 2.500 -1.000 2.440-2.540 2.470-2.520 3 17Chicago-Peoples 2.840 -1.000 2.740-2.940 2.800-2.900 3 1Consumers city-gate 2.595 -0.060 2.555-2.605 2.585-2.605 210 32Dawn, Ontario 2.595 -0.085 2.580-2.620 2.585-2.605 618 94Emerson, Viking GL 2.530 -0.070 2.490-2.580 2.510-2.555 96 26Mich Con city-gate 2.580 -0.050 2.545-2.590 2.570-2.590 201 30Northern Bdr., Ventura TP 2.415 -0.035 2.390-2.440 2.405-2.430 43 9REX, Zone 3 delivered 1.440 -1.000 1.240-1.640 1.390-1.490 1 18

Gulf Coast

Agua Dulce Hub --- --- ------- ------- --- ---ANR, La. 2.315 -0.105 2.280-2.360 2.295-2.335 23 7Carthage Hub 2.350 +0.005 2.350-2.350 2.350-2.350 12 2Henry Hub 2.435 -0.025 2.400-2.455 2.420-2.450 145 19Houston Ship Channel 2.450 -0.005 2.430-2.500 2.435-2.470 60 9Katy 2.390 -0.055 2.360-2.410 2.380-2.405 238 30NGPL, STX --- --- ------- ------- --- ---NGPL, Texok zone 2.375 -0.010 2.355-2.450 2.355-2.400 218 44Tx. Gas, zone 1 2.355 +0.000 2.320-2.375 2.340-2.370 132 21Tx. Gas, zone SL 2.365 +0.015 2.365-2.365 2.365-2.365 9 1Trunkline, WLA --- --- ------- ------- --- ---Trunkline, ELA --- --- ------- ------- --- ---Trunkline, zone 1A 2.365 -0.010 2.335-2.370 2.355-2.370 71 13

Midcontinent

ANR, Okla. 2.345 +0.010 2.345-2.350 2.345-2.345 85 15Enable Gas, East 2.325 +0.030 2.310-2.350 2.315-2.335 68 9NGPL, Amarillo receipt 2.370 +0.005 2.360-2.390 2.365-2.380 78 14NGPL, Midcontinent 2.350 +0.015 2.330-2.365 2.340-2.360 282 37Northern, demarc 2.425 -0.015 2.400-2.440 2.415-2.435 100 19Northern, Ventura 2.415 -0.025 2.400-2.440 2.405-2.425 32 4Oneok, Okla. 2.255 +0.025 2.250-2.270 2.250-2.260 110 19

Platts enerGy trader sParK sPreads, seP 30 ($/MWh)

Midwest Chicago entergy Houston Median Change Peak Change Median Change Peak Change Median Change Peak Change Median Change Peak ChangeGas -2.37 2.17 -16.88 2.65 -2.31 1.12 -7.91 1.30 -0.83 -0.42 -7.45 -0.29 -1.50 0.49 -7.28 0.46Oil -45.25 0.09 -80.58 -0.33 -50.01 -0.73 -51.62 -0.75 -41.44 -1.89 -75.54 -2.31 -41.81 -0.26 -41.90 -0.26Coal 4.33 1.01 10.30 1.01 4.34 0.49 5.37 -0.74 5.39 0.89Nuclear 27.56 1.01 23.49 0.18 23.94 -1.03 23.60 0.60


($/MMBtu)

3.0

3.5

4.0

4.5

5.0

16-Jan15-Jan14-Jan13-Jan10-Jan

Henry Hub cash priceNYMEX front month close

HENRY HUB/NYMEX SPREAD

Central Gas MarKets

Midwest prices fall on cool forecastUpper Midwest cash prices fell Wednesday on unseasonably cool weather that is expected to linger through the next couple days.

Temperatures in Chicago are forecast to rise to a high of 61 degrees Thursday, slightly below Wednesday’s estimated high of 62 degrees and well below the average high of 71. Commonwealth Edison is forecasting an hourly peak load of nearly 11.6 GW Thursday, a tick above Wednesday’s estimate of nearly 11.5 GW. In the cash market, Chicago city-gates prices slid 8 cents.

In Detroit, highs are expected to reach 61 degrees Thursday, below the seasonal norm of 69. The Midcontinent Independent System Operator estimates peak hour demand at 79 GW Thursday down from Wednesday’s peak estimate of about 82 GW.

Prices at Michigan Consolidated and Consumers slid about 8 cents.

Closer to the producing region, Northern Natural Gas’ point in Ventura, Iowa, fell 6 cents. High temperatures in Minneapolis are forecast to reach 61 degrees Thursday, down from a norm of about 66 degrees.

In the Midcontinent region, cash prices were mostly down amid the expected pullback in power demand.

Platts unit Bentek Energy estimates that natural gas-fired power demand will average 1 Bcf/d on Thursday, down from Wednesday’s estimate of 1.2 Bcf/d.

Gas-fired power demand in the producing states of Oklahoma, Kansas and Missouri is expected to fall to 772 MMcf/d from 981 MMcf/d over the same period.

Natural Gas Pipeline Co. of America’s Midcontinent zone fell by more than 7 cents.

Panhandle Eastern Pipeline fell by 18 cents, while ANR Pipeline-Oklahoma was flat.



day-ahead electric lMP MarketS for oct 1 ($/MWh) Avg MarginalHub/Zone Average Cong Loss Change $/Mo heat rate

CAISO on-peak

NP15 Gen Hub 33.81 -0.21 -1.04 -1.24 33.81 11300SP15 Gen Hub 33.98 0.00 -1.09 -2.19 33.98 13416

CAISO off-peak

NP15 Gen Hub 28.27 -0.16 -0.46 1.22 28.27 9279SP15 Gen Hub 27.98 0.00 -0.91 1.11 27.98 10739

near-terM MarketS ($/MWh)Contract transacted deal

Mid-C

Bal-week 09/30 22.75-23.25Bal-week 09/29 25.25-25.75Bal-week 09/28 26.50-27.00Bal-month 09/30 24.00-24.50Bal-month 09/24 26.25-26.75Bal-month (off-peak) 09/30 21.75-22.25Bal-month (off-peak) 09/28 24.75-25.25Bal-month (off-peak) 09/24 23.50-24.00Next-week 09/30 25.75-26.25Next-week 09/29 26.00-26.50Next-week 09/28 25.75-26.25Next-week 09/24 26.25-26.75Next-week (off-peak) 09/29 23.75-24.25Next-week (off-peak) 09/24 23.50-24.00


West

Colgate Hydro-2/PCWA 176 h Calif. MO Unk 09/27/15Helms Pump-1/PG&E 407 h Calif. PMO Unk 09/27/15Hoover-2/SCE 525 h Nev. PMO Unk 09/29/15Inland-2/Inland Empire 366 g Calif. MO Unk 09/22/15La Rosita-1/Intergen 180 g Mex. PMO Unk 08/05/15Middle Fork/PCWA 218 h Calif. PMO Unk 09/29/15Midway Peaking/Starwood 120 g Calif. MO Unk 09/29/15Pine Flat/CDWR 210 h Calif. MO Unk 08/23/15

WeStern day-ahead bilateral indexeS for oct 1 ($/MWh) Avg Marginal Index Change $/Mo heat rate

on-peak

Mid-C 24.92 -1.99 24.92 9840John Day 26.00 -2.00 26.00 10267COB 25.98 -4.02 25.98 10582NOB 27.25 -1.75 27.25 10760Palo Verde 27.94 -1.96 27.94 11369Westwing 29.25 -1.25 29.25 11902Pinnacle Peak 31.00 1.00 31.00 12614Mead 30.00 -1.00 30.00 11858Mona 28.00 -1.25 28.00 12017Four Corners 33.00 3.50 33.00 13836

off-Peak

Mid-C 22.65 -2.37 22.65 8944John Day 23.75 -2.25 23.75 9378COB 22.72 -1.67 22.72 9255NOB 23.50 -2.50 23.50 9279Palo Verde 22.00 0.00 22.00 8952Westwing 21.50 -0.50 21.50 8749Pinnacle Peak 22.50 0.00 22.50 9156Mead 23.25 -0.25 23.25 9190Mona 22.50 0.25 22.50 9657Four Corners 21.00 1.00 21.00 8805

West PoWer MarKets

Mid-C slips to mid-$20s/MWhDay-ahead power prices were down across the West midweek with peakload set to pull back on the first day of a new month.

In California, SP15 on-peak gave up more than $2 in the mid-$30s/MWh for Thursday delivery on the IntercontinentalExchange. Last October, SP15 Gen Hub on-peak averaged at $48.75/MWh.

The California Independent System Operator forecast peakload at 34,889 MW Wednesday and 34,319 MW for the first day of October, higher than where peakload averaged in October 2014 at 31,700 MW.

In the Northwest, Mid-Columbia on-peak lost $2 averaging near $25/MWh for Thursday delivery. Off-peak also gave up $2 to below $23/MWh. In October last year, Mid-Columbia on-peak averaged below $33/MWh.

The Pacific Northwest continues to look toward neighboring regions to help fill in where below-normal water supplies have left a gap in hydro generation this year.

Exports to the US from Canada on the BC Intertie averaged over 1,400 MW at the start of this week, which is up about 8% compared with the previous week’s average and well above the September 2014 average of 109 MW.

In the Southwest, Palo Verde on-peak moved down almost $2 in the upper $20s/MWh. Off-peak lost around 25 cents in the low $20s/MWh.

Power prices remain below levels seen last year as regional spot gas prices were around 38% lower year-on-year. Last October, Palo Verde on-peak power averaged close to $38.50/MWh.

With weaker fuel prices this year, Arizona’s total natural-gas fired electricity generation was up during the first seven months of the year compared with same period in 2014, while coal generation was down.

Natural-gas fired generation produced nearly 16,000 GWh from January through July, an increase of nearly 15% from the prior year, while coal dropped to just over 21,000 GWh, a decrease of nearly 14%, according to the most recent data from the Energy Information Administration.

Solar generation also saw growth as its year-over-year production rose over 10% to about 2,100 GWh.

Western forward power fell midweek as November packages moved into the prompt-month position. November NYMEX gas futures were dropped 6.2 cents to $2.524/MMBtu, which helped pull down terms.

Mid-Columbia on-peak November fell 75 cents to $25/MWh. SP15 on-peak November gave up 50 cents to $33.25/MWh. Palo Verde on-peak November was down 75 cents to $25.50/MWh.

West prompt-month power packages are about 30% lower than where November 2014 packages stood at this time last year.

For instance, Mid-Columbia on-peak November was near $39/MWh and rolled off the curve around $32/MWh in late October 2014. SP15 on-peak November was around $48/MWh and hit at $45/MWh by the end of the month. Palo Verde on-peak November was just below $38/MWh when it rolled into prompt-month spot and then moved down to just below $36/MWh.




California

PG&E, Malin 2.390 +0.015 2.380-2.400 2.385-2.395 146 27PG&E, South 2.515 +0.070 2.470-2.550 2.495-2.535 159 20PG&E, city-gates 2.945 -0.015 2.940-2.980 2.940-2.955 412 46SoCal Gas 2.510 +0.055 2.470-2.540 2.495-2.530 798 71SoCal Gas, city-gate 2.765 +0.065 2.750-2.785 2.755-2.775 463 51

rockies/northwest

Cheyenne Hub 2.290 -0.015 2.280-2.300 2.285-2.295 37 6CIG, Rockies 2.250 +0.050 2.240-2.260 2.245-2.255 113 20El Paso, Bondad 2.335 +0.015 2.330-2.340 2.335-2.340 120 15El Paso, San Juan 2.345 +0.010 2.340-2.350 2.345-2.350 234 40El Paso, South Mainline 2.545 -0.005 2.535-2.570 2.535-2.555 80 8GTN, Kingsgate 2.200 +0.015 2.200-2.200 2.200-2.200 31 4Kern River, Opal 2.335 +0.015 2.300-2.340 2.325-2.340 483 68Kern River, delivered 2.535 +0.030 2.515-2.600 2.515-2.555 378 45NW, Wyo. pool 2.285 +0.050 2.250-2.330 2.265-2.305 40 6NW, south of Green River 2.265 +0.015 2.250-2.270 2.260-2.270 80 11NW, Can. border (Sumas) 2.255 +0.060 2.230-2.270 2.245-2.265 299 47Questar, Rockies 2.270 +0.030 2.270-2.270 2.270-2.270 3 1Stanfield, Ore. 2.270 +0.005 2.270-2.270 2.270-2.270 91 10TCPL Alberta, AECO-C* 2.500 +0.005 2.490-2.520 2.495-2.510 1,394 96Transwestern, San Juan 2.345 +0.015 2.330-2.350 2.340-2.350 191 23Westcoast, station 2* 0.730 +0.020 0.640-0.750 0.705-0.750 314 48White River Hub 2.300 +0.025 2.290-2.310 2.295-2.305 48 9

West texas

El Paso, Permian 2.350 +0.015 2.340-2.355 2.345-2.355 339 52Transwestern, Permian 2.325 +0.050 2.320-2.340 2.320-2.330 70 11Waha 2.345 -0.005 2.300-2.370 2.330-2.365 192 22

* TCPL Alberta, AECO-C and Westcoast station 2 prices are in Canadian dollars per gigajoule.

nyMex Henry HuB Futures ContraCt ClosinGs, seP 30

Month High low Close Change

Nov 2015 2.611 2.511 2.524 -0.062Dec 2015 2.786 2.694 2.701 -0.062Jan 2016 2.905 2.821 2.831 -0.053Feb 2016 2.910 2.832 2.842 -0.049Mar 2016 2.877 2.803 2.814 -0.047Apr 2016 2.749 2.680 2.688 -0.043May 2016 2.732 2.689 2.695 -0.040Jun 2016 2.765 2.724 2.731 -0.039Jul 2016 2.825 2.760 2.769 -0.037Aug 2016 2.812 2.774 2.780 -0.038Sep 2016 2.806 2.770 2.774 -0.039Oct 2016 2.833 2.794 2.801 -0.039Nov 2016 2.911 2.876 2.881 -0.037Dec 2016 3.080 3.043 3.050 -0.036Jan 2017 3.180 3.145 3.152 -0.037Feb 2017 3.168 3.146 3.146 -0.035Mar 2017 3.107 3.081 3.086 -0.034Apr 2017 2.880 2.845 2.853 -0.033

open int., sep 29: 906835; total volume, sep 29: 255583.

Platts enerGy trader sParK sPreads, seP 30 ($/MWh) northwest northern California southern California

Median Change Peak Change Median Change Peak Change Median Change Peak ChangeGas -4.10 -4.48 -9.66 -4.96 3.94 -0.44 -6.27 -0.17 5.17 -1.05 -4.56 -0.67Coal 19.74 -1.99Nuclear 20.37 -1.99 29.32 -1.24 29.11 -2.19


West Gas MarKets

northwest prices follow nyMex futures lowerNorthwest spot natural gas prices mostly dropped Wednesday as weakness in the futures market offset expectations for slightly higher demand in downstream regions.

Opal dropped 7 cents, while Cheyenne Hub was down nearly 10 cents.

In Western Canada, Spectra said in a notice on its website that it was reducing capacity at the Huntingdon delivery area to about 1 Bcf/d effective Thursday. The capacity is equivalent to 76% of firm contracted service, and the next capacity adjustment is scheduled for October 7, Spectra said.

Northwest Canadian border (Sumas) jumped 23 cents.Spectra said its McMahon Gas Plant experienced a total outage,

bringing plant flow to zero. All gathering compression was offline and producers were requested to shut in until the problem at McMahon has been resolved, according to the Spectra notice.

In the Southwest, cash prices fell Wednesday, despite a small increase in expected demand.

Bentek Energy, a unit of Platts, projected total West demand at 10.3 Bcf Thursday, up from 10.2 Bcf Wednesday.

Prices at the Pacific Gas and Electric city-gate dropped 7 cents to $2.99/MMBtu, marking the first time the Northern California city-gate price has averaged below $3/MMBtu since early June.

At the Southern California Gas city-gate, prices fell nearly 8 cents.



PlattS M2MS forWard curve — electricity, SeP 30 ($/MWh)Prompt month: nov 15

Mass Hub 53.00N.Y. Zone G 45.40N.Y. Zone J 47.35N.Y. Zone A 36.45Ontario* 20.25PJM West 38.95AD Hub 36.35NI Hub 33.05Indiana Hub 33.30Southern Into 34.30Entergy Into 32.20ERCOT North 25.40Houston 26.20ERCOT West 24.65ERCOT South 25.40Mid-C 24.90Palo Verde 25.65NP15 35.50SP15 33.15Mead 26.60

All prices are on-peak *Ontario prices are in Canadian dollars

($/MWh) ($/MWh)

(Btu/kWh)

Table and graphs are created using Platts–ICE Forward Curve — Electricity (North America) data. Both on-peak and o�-peak electricity forward assessments are available for periods spanning four years. To see a sample and �nd information on how to subscribe to the full data set go to www.platts.com/risk. For more information about Platts services, please call +1-800-PLATTS8. For editorial questions

10000

12000

14000

16000

18000

01-Jul23-Jun15-Jun05-Jun28-May

XX: Marginal heat rate

Month 1 Month 2

30

40

50

60

01-Jul22-Jun12-Jun04-Jun22-May14-May

XX: last 30 days

May

16

Jun1

6Se

p16

Jan/

Feb1

6M

ar/A

pr1

6Ju

l/Aug

16

Q4

16

Cal

19

Cal

16

Cal

17

Cal

18

Dec

15

Nov

15

Jan1

6

Jan/

Feb1

7M

ar/A

pr1

7Ju

l/Aug

17

May

17

Jun1

7Se

p17

Q4

17

0

20

40

60

XX: Forward curve

Nov 15 Q415CY16 Jan/Feb 16

Nov 15 Q215CY16 Q116

Jan1

6

Dec

15

Q1

16

Q2

16

Q3

16

Cal

16

Cal

17

Cal

18

Q4

16

Q1

17

Q2

17

Q3

17

Q4

17

Cal

19

Nov

15

Nov 15 CY16 Jan/Feb 16Mar/Apr 16

PlattS M2MS forWard curve — natural GaS, oct 7 ($/MMBtu)Prompt month: nov 15Algonquin, city-gates 2.805Transco, zone 6-NY 0.150Texas Eastern, M-3 -0.825Columbia Gas, Appalachia -0.150Dominion, South Point -1.168Transco, zone 3 -0.012Transco, zone 4 0.002Southern Natural, LA -0.043Tennessee, 500 Leg -0.067Florida Gas, zone 3 -0.007Columbia Gulf, mainline -0.085Houston Ship Channel -0.045NGPL, Texok -0.070Chicago city-gates 0.138MichCon city-gate 0.243Dawn, Ontario 0.305Panhandle, TX-Okla. -0.210Northern, Ventura 0.113Northern, demarc 0.103Waha -0.110El Paso, Permian Basin -0.120El Paso, San Juan Basin -0.110PG&E city-gate 0.455PG&E, Malin 0.005SoCal Gas 0.060Northwest, Rockies -0.093Northwest, Sumas -0.180AECO, Alberta -0.485

Summer season is April-October. Winter is November-March. *Balance-of-season.

$/MMBtu $/MMBtu

$/MMBtu

Table and graphs are created using Platts M2MS-Gas data. Forward assessments as basis to the Henry Hub and full values are available for periods spanning 10 years. To see a sample and �nd information on how to subscribe to the full data set go to www.platts.com/risk. For more information on Platts services, please call +1-800-PLATTS8. For editorial questions, call Mark Callahan +713-658-3211.

2.6

2.8

3.0

3.2

3.4

3.6

28-Sep18-Sep10-Sep01-Sep24-Aug14-Aug

0

1

2

3

4

Chicago city-gates: Key packages, last 30 days Chicago city-gates: Forward curve

Chicago city-gates: Basis market vs NYMEX

2.5

2.6

2.7

2.8

2.9

3.0

28-Sep18-Sep10-Sep01-Sep24-Aug14-Aug

Cal 1

6

Prompt month basisPrompt month NYMEX

spot price, last 30 daysWinter 15-16

Summer 16Cal 16

October 15

Cal 1

7

Su

mm

er 18

Su

mm

er 17

No

vemb

er 15

Win

ter 16

-17

Su

mm

er 16

Win

ter 15

-16

Decem

ber 1

5

Octo

ber 1

5

Cal 1

8

Win

ter 17

-18

Febru

ary 16

March

16

Jan

uary 1

6



generation dropped as low as 800 MW below forecast at 10 am. All other load zones and hubs averaged about $25/MWh.

ERCOT forwards were weaker Wednesday as NYMEX November gas futures lost 6.2 cents to about $2.524/MMBtu.

ERCOT North Hub November on-peak real-time financial traded 100 MW at $25.35/MWh and cleared 200 MW at $25/MWh on the Intercontinental Exchange by 2:30 pm EDT. On-peak day-ahead financial traded 100 MW at $25.50/MWh and cleared 100 MW at $25.15/MWh. Last year, the November 2014 on-peak package averaged $35/MWh in October, 28% above where this year’s November package is starting the month. November on-peak heat rates traded 150 MW at 9.92 MMBtu/MWh. December on-peak cleared 200 MW through ICE at $25.50/MWh.

expected in the lower 50s to mid-60s.Mid-Atlantic forwards were flat to lower Wednesday afternoon amid

slipping NYMEX gas futures and steady regional gas basis.PJM West Hub on-peak November was unchanged at roughly $39/MWh

on the IntercontinentalExchange around 2:30 pm EDT. The PJM November contract was about $1 below the 30-day average and nearly $4 below contract levels October last year. PJM West Hub on-peak December was also unchanged at about $42/MWh, while the on-peak January-February package sank $1.25 to around $55.75/MWh.

NYMEX November gas futures dropped 6.2 cents to $2.524/MMBtu, while Texas Eastern M-3 November gas basis moved just 0.2 cents higher to negative 68.8 cents/MMBtu.

In the Southeast, dailies were stronger Wednesday with temperatures forecast to fall 10 degrees.

Into Southern day-ahead on-peak physical power added $1.25 in the upper $20s/MWh for Thursday delivery on ICE. Into Southern off-peak traded 50 MW at $23/MWh on ICE.

Spot natural gas at Transco Zone-3 lost 3.5 cents to about $2.445/MMBtu on ICE.

The high temperature in Atlanta was forecast dropping to 72 Thursday, 6 degrees below normal, with the low expected at 66, 7 degrees above normal.

east Power ... from page 2

Central Power ... from page 4

assessMent rationalePlatts Gas Daily indices are based upon trade data reported to Platts by market participants. The indices are calculated using detailed transaction level data from these providers. Platts editors screen the data for outliers that may be further examined and potentially removed. A volume weighted average is then calculated from the remaining set of data. For more details on this methodology please see our North American Natural Gas Methodology and Specifications Guide on Platts.com, located at http://www.platts.com/IM.Platts.Content/MethodologyReferences/MethodologySpecs/na_gas_methodology.pdf

Questions may be directed to Patrick Badgley at 713-658-3267 or [email protected]

Platts proposes new rex natural gas indexes Following initial market research, Platts is proposing the addition of the following indexes in its daily natural gas survey. The new locations would appear as follows:

REX, Moultrie (daily survey only)

Deliveries from Rockies Express Pipeline to the Natural Gas Pipeline Co. of America pipeline at the Moultrie County, Illinois interconnect.

REX, Edgar (daily survey only)

Deliveries from Rockies Express Pipeline to Midwestern Gas Transmission at the Edgar County, Illinois interconnect.

REX, Shelby (daily survey only)

Deliveries from Rockies Express Pipeline to ANR Pipeline at the Shelby County, Indiana interconnect.

The new indexes would appear beginning with the Gas Daily price table showing trade date Friday, October 30, 2015, for flow dates Sunday, November 1, and Monday, November 2. The proposed listings would appear in the “Others” section of Gas Daily’s “Daily Price Survey” table, and Platts Natural Gas Alert page 514.

Please send any comments to [email protected] and [email protected] by Friday, October 9.

For written comments, please provide a clear indication if comments are not intended for publication by Platts for public viewing. Platts will consider all comments received and will make comments not marked as confidential available upon request.

suBsCriBer note

Platts proposes new Chicago natural gas indexes Following initial market research, Platts is proposing the addition of the following new indexes in its daily and monthly natural gas surveys. The new locations would appear as follows:

Chicago-Nicor (daily and monthly survey) Deliveries into the Nicor Gas system in the Chicago metropolitan area. Transactions are also included in the Chicago city-gates index.Chicago-NIPSCO (daily and monthly survey) Deliveries into Northern Indiana Public Service system in the Chicago metropolitan area. Transactions are also included in the Chicago city-gates index.Chicago-Peoples (daily and monthly survey)

Deliveries into the Peoples Gas Light & Coke system in the Chicago metropolitan area. Transactions are also included in the Chicago city-gates index. The Chicago city-gates index will not be altered based on the new Chicago sublistings.

The new indexes would appear beginning with the Gas Daily price table showing trade date Friday, October 30, 2015, for flow dates Sunday, November 1, and Monday, November 2, and for the November 2015 monthly Bidweek survey with trade dates October 26-30.

The proposed listings would appear in the “Upper Midwest” section of the “Market Center Spot Gas Prices” table in Inside FERC’s Gas Market Report, Energy Trader and Gas Daily Price Guide, in the “Citygates” section of Gas Daily’s “Daily Price Survey” table, and Platts Natural Gas Alert pages 434, 496 and 515.

Additionally, they would appear in the “Upper Midwest” section of the “Market Center Bidweek Physical Basis Prices” table in Inside FERC’s Gas Market Report.

Please send any comments to [email protected] and [email protected] by Friday, October 9.

For written comments, please provide a clear indication if comments are not intended for publication by Platts for public viewing. Platts will consider all comments received and will make comments not marked as confidential available upon request.



in tHe neWs

new england basis falls, nyMex downFinancial basis markets in New England fell sharply Wednesday, while other markets mostly saw small moves higher as the NYMEX November contract traded lower.

The NYMEX November natural gas futures contract traded lower for a second-straight day Wednesday, falling 6.2 cents to settle at $2.524/MMBtu.

In New England, Algonquin Gas Transmission city-gates November basis dropped 21 cents to plus $2.45/MMBtu. Algonquin winter 2015-16 basis fell about 19 cents to plus $5.05/MMBtu.

Market assessments are considered preliminary and based on market activity on IntercontinentalExchange at 2:25 pm EDT (1825 GMT).

The National Weather Service Climate Prediction Center’s six- to 10-day outlook called for a mild start to fall in the Northeast, with above-average temperatures expected across the New England region. Above-average temperatures also were forecast across the Western US, as well as the southern Midcontinent and portions of Florida. Below-average temperatures were expected in portions of the Upper Midwest and parts of the Southeast.

The NWS eight- to 14-day forecast called for above-average temperatures across the entire continental US, with the exception of the Great Lakes region, which was expected to experience near-normal temperatures.

Texas Eastern Transmission M-3 November basis held flat at minus 69 cents/MMBtu. TETCO December basis slipped 3.5 cents to plus 31.5 cents/MMBtu.

Upstream in the Northeast producing regions, Dominion Transmission South Point November basis moved higher, adding 1.5 cents to minus $1.135/MMBtu.

Toward the Gulf Coast, Houston Ship Channel November basis added 1.5 cents to minus 4.25 cents/MMBtu. Ship Channel December basis saw a smaller increase, tacking on 0.4 cent to minus 7.1 cents/MMBtu.

Around the Upper Midwest, Chicago city-gates winter 2015-16 basis rose a little more than 1.5 cents to plus 27.5 cents/MMBtu.

Around the Western producing regions, Northwest Pipeline-Rockies November basis added 0.75 cent to minus 7 cents/MMBtu.

Northwest Pipeline-Sumas November basis saw a bigger increase, climbing 2 cents to minus 12 cents/MMBtu.

Along the West Coast, Southern California Gas winter 2015-16 basis added nearly 1 cent to plus 5.5 cents/MMBtu.

According to a notice SoCal Gas issued Tuesday afternoon, the pipeline will be performing planned remediation work on its Line 235 in the Needles/Topock Area Zone through December 18. Work began September 13 and was previously scheduled to end November 1. During the maintenance period capacity reductions of 500 MMcf/d are expected.

Pacific Gas and Electric winter basis also tacked on a little more than a half cent to plus 29 cents/MMBtu.

Upstream in western Canada, AECO-NIT November basis rose 2 cents to minus 48.75 cents/MMBtu.

— Curt Mrowiec

nortH aMeriCan daily Generation outaGes By reGion, seP 30

iso region MW oFF

AESO 1,815CAISO 1,394ERCOT 2,412ISONE 2,845MISO 15,963NYISO 814Ontario IESO 5,398PJM 16,112SPP 6,623

nerC region MW oFF

ERCOT 2,412FRCC 2,958MRO 4,318NPCC 9,241RFC ECAR 11,277RFC MAAC 5,973RFC MAIN 2,654SERC 17,812SPP 6,623WECC 10,817US TOTAL 74,084

Source: IIR Energy

For more information please contact IIR Energy at [email protected] or at their website, www.iirenergy.com

Renewable/Other (5,138)

Nuclear (28,030)

Natural/Other Gas (25,295)

Fuel Oil (2,616)

Coal (60,255)

US MEGAWATTS OFFLINE BY FUEL TYPE

oil futures stable; Cushing draw offsets us buildNYMEX November crude fell slightly Wednesday, settling down 14 cents to $45.09/b after the US Energy Information Administration’s weekly inventory report provided mixed signals.

ICE November Brent settled 14 cents higher at $48.37/b.NYMEX October ULSD settled 1.5 cents higher at $1.5126/gal,

while NYMEX October RBOB settled up 2.62 cents to $1.3894/gal. The October contract for NYMEX refined products expired Wednesday.

US commercial crude stocks rose 3.955 million barrels to 457.924 million barrels in the week ended September 25, EIA data showed Wednesday.

Analysts surveyed Monday by Platts expected stocks were unchanged.

A slowdown in refinery operations and uptick in imports helped push inventories higher, negating a drop in crude production.

“Fairly neutral report, with things for both bulls and bears to cling to,” said Anthony Starkey, energy analysis manager at Bentek Energy, a unit of Platts.

mailto:[email protected]



US crude runs fell 241,000 b/d to 15.962 million b/d, the first time refiners processed less than 16 million b/d since early May.

Last week’s decrease in crude demand was consistent with seasonal trends, as refiners scale back operations to conduct planned repairs typically lasting from late September through November.

The refinery utilization rate dropped 1.1 percentage points to 89.8% of operable capacity, suggesting the autumn turnaround season has begun.

Analysts were looking for the utilization rate to have fallen 0.6 percentage point.

By region, the biggest build occurred on the Gulf Coast, where crude stocks increased 5.15 million barrels to 235.677 million barrels.

Gulf Coast imports increased 244,000 b/d to 2.895 million b/d, helping the region’s stocks build.

Total imports were up 378,000 b/d to 7.554 million b/d, corresponding with a tightening of the Brent/WTI spread.

The front-month ICE Brent/WTI has mostly been in a band of $2-$3/b since mid-September, its tightest range since January. Brent’s premium to WTI had exceeded $7/b in mid-August before beginning to erode steadily.

“Imports could stay above seven and a half million barrels a day with increased Canadian flows and there are a lot of cargoes floating around attracted to WTI prices right now,” said Jim Ritterbusch, president of Ritterbusch & Associates.

By country of origin, imports from Iraq rose 187,000 b/d last week to 258,000 b/d.

A tanker carrying around 995,000 barrels of Iraqi Basrah Heavy crude was headed last week to the offshore Galveston lightering area on the Gulf Coast, cFlow, Platts trade flow software, showed.

Apart from imports, another factor behind the Gulf Coast build could have been increased flows from the Midwest, where stocks drew 3.759 million barrels to 131.638 million barrels.

Stocks at Cushing, Oklahoma — delivery point for the NYMEX crude futures contract — decreased 1.068 million barrels to 52.974 million barrels.

Cushing inventories have decreased a total of 4.7 million barrels over the last four reporting periods as the financial incentive to store crude has eased.

NYMEX crude’s contango has narrowed since mid-August, making it more difficult for traders to profit from storage.

Prompt NYMEX crude oil averaged $5.08 per barrel (/b) less than the price for delivery 12 months out during September through the end of last week, compared with $6.80/b in August.

The discount for prompt NYMEX crude has lessened partly due to signs US crude production has finally begun to turn lower in response to cheaper oil prices.

Output in the Lower 48 states fell last week by 21,000 b/d to 8.627 million b/d. US output, excluding Alaska, has decreased or been unchanged since the week ended August 7.

“US crude output is on a declining path for now,” and may not rise again until the second quarter of 2016, Citi Research analysts said in a note.

— Geoffrey Craig

eia to estimate 98-102 bcf injection: analystsThe US Energy Information Administration is expected to estimate a natural gas storage injection of between 98-102 Bcf for the reporting week ended September 25, according to a consensus of analysts surveyed by Platts.

EIA will publish its storage report at 10:30 am EDT Thursday.An injection within expectations would be below the 110-Bcf

injection reported at this time last year, but above the 94-Bcf five-year average build. The wider range of analysts’ expectations for this week was for an injection of 78-104 Bcf.

EIA reported a 106-Bcf injection for the week ended September 18 that increased inventories to 3.440 Tcf — about 16% above year-ago inventories and almost 5% more than the five-year average.

“The expected injection comes one week after the EIA announced an injection above last-year’s levels for only the second time since July, and will likely come in below the comparable injection from a year ago as demand picked up from the previous week,” analysts from Platts unit Bentek Energy said.

Bentek estimated that total demand increased nearly 700 MMcf/d week-over-week, driven primarily by power burn demand.

Analysts pointed to seasonable shoulder-month weather, which led to a slack demand, coupled with still relatively robust production as the factors driving the triple-digit injection.

Tom Saal, an analyst with FC Stone who predicted that the EIA would estimate a 98-Bcf injection, said that an injection of around 100 Bcf would be “pretty much in line,” with historical averages.

“We’re in a shoulder period between now and the first cold front later in the month of October,” he said. “You have a lack of seasonal demand, and the inventory injections confirm that lack of demand.”

Saal added that the next few weeks of injections “ought to be pretty large and that’s one of the reasons why prices are weak.”

Kyle Cooper, an analyst with IAF Advisors, cited moderate temperatures and US production that “remains pretty high,” despite lackluster gas prices as the twin drivers of the robust injections to storage.

Gene McGillian, an analyst with Tradition Energy, agreed with the majority of analysts surveyed that the EIA’s weekly estimate of storage injections would come in right around the century mark. “People are a little above and below that, but with the production level and the weather we’re set for another triple-digit injection,” he said.

Representing the contrarian view was Price Futures Group analyst Phil Flynn, whose estimate of a 78-Bcf was at the far low end of the survey. Flynn cited a marked increase in demand for electric power during the week as the primary driver for his bullish prediction.

— Jim Magill

Jordan Cove lnG clears environmental hurdleThe Jordan Cove LNG export project planned for Coos Bay, Oregon, took an important step toward securing regulatory approval Wednesday, when the US Federal Energy Regulatory Commission released the environmental impact statement for the project and an





associated pipeline.The EIS schedule had twice been delayed, most recently because

the Department of the Interior’s Bureau of Land Management required more information from Pacific Connector about an alternative pipeline route affecting BLM lands. December 29 is the federal authorization decision deadline for the LNG project and pipeline.

FERC staff in the EIS found the projects would have some limited adverse impacts, but that those could be reduced to “less-than-significant” levels with mitigation measures proposed by the applicants and further steps suggested in the EIS (CP13-483, CP13-492).

Jordan Cove has said the project would use competitively priced gas from Western Canadian and Rocky Mountain sources to export to overseas markets around the Pacific Rim.

It filed an application in May 2013 to build liquefaction and export facilities, including four liquefaction trains, two 160,000-cubic-meter full-containment storage tanks and a new marine slip with two berths. The export terminal, estimated to cost $5.3 billion, would be capable of liquefying the LNG equivalent of 900 MMcf/d of gas.

Pacific Connector Gas Pipeline in June 2013 applied to build a 232-mile pipeline to feed gas to the facility. The 1.06-million Dt/d pipeline would connect with Ruby Pipeline and Gas Transmission Northwest near Malin, Oregon, and run to the proposed export project in Coos County. The $1.74 billion project would also include a 41,000-horsepower compressor station in Klamath County, as well as a number of meter stations.

The projects have faced vehement opposition from the environmental community, which contends the facilities would increase the region’s dependence on natural gas and encourage hydraulic fracturing. Others had focused opposition on the LNG terminal’s location in an area vulnerable to earthquakes and tsunamis, and on the risk of wildfires along the pipeline route.

Addressing some of those concerns, the EIS said the final terminal design would include seismic specifications and other measures to reduce the impacts from future earthquakes and potential tsunamis. For instance, Jordan Cove would raise the LNG processing area and surround storage tanks with a storm-surge barrier about 60 feet high. The EIS also noted that Pacific Connector would put in place a fire prevention and suppression plan.

BlM to amend land management plansBLM would amend its land management plans for areas including

national forests thorough which the pipeline would traverse. The EIS said BLM could issue a right of way for the pipeline easement over federal lands. That would require concurrence with the Forest Service and Bureau of Reclamation, based on a plan of development that would include further mitigation.

FERC staff also said other agencies will offer further biological opinions and make recommendations to avoid harm to species under their jurisdiction or destruction of critical habitat.

The report sets an additional 102 environmental conditions for the project. It notes that 821 acres of late-successional old growth forest would be impacted by the pipeline, but that the Pacific Connector would compensate with a wildlife habitat mitigation plan.

The report mentions alternatives FERC considered, including the use of existing jurisdictional pipelines. Those were rejected as impractical because either the routes failed to connect the right locations or the systems couldn’t handle sufficient volumes of gas. It said other LNG facilities on the Gulf Coast or East Coast were not reasonable alternatives because they would have longer, less direct routes to Asia, and draw gas from different parts of the country.

The EIS acknowledged that the LNG project could be a significant source of greenhouse gas emissions but found it could also reduce emissions by displacing coal use in Asia. The displacement “depends on a multitude of complex geological and economic factors that cannot reasonably be foreseen,” the EIS said.

In Washington, the EIS was welcomed by Senator John Barrasso, Republican-Wyoming, who had written FERC several times to express support for the project. He called on DOE to quickly give approval, saying the administration needs to give West Coast communities opportunities to access overseas markets that their Gulf Coast and East Coast counterparts have enjoyed.

“It must not leave the West behind,” he said.— Maya Weber

Broad energy bill clears House committeeScrapping a nearly seven-month effort to craft a broad energy bill with support from both sides of the aisle, House Republicans added controversial elements back to energy legislation that cleared a committee vote Wednesday.

The House Energy and Commerce Committee passed the bill in a 32-20 vote, with only three Democrats supporting the legislation. Most Democrats on the panel contended that the bill as reported was not something President Barack Obama would ever sign into law.

Notably, the version of the bill that passed the House Energy and Commerce subcommittee on energy and power in July was praised for the bipartisan support it garnered. Committee leadership at the time agreed that provisions in the comprehensive energy measure should be generally accepted by both Democrats and Republicans.

However, the Republican majority on the committee unveiled a substitute bill Tuesday that was pushed through as a manager’s amendment in a voice vote Wednesday.

The majority’s amendments included elements left out of the bill at the subcommittee level in the spirit of bipartisanship, including steps to speed LNG exports, hydropower permitting reforms and a measure with implications for capacity markets.

Frank Pallone, the top Democrat on the committee, accused committee Chairman Fred Upton, Republican-Michigan, of abandoning an agreement the two reached in July to continue moving forward in a bipartisan nature. That agreement, the ranking member from New Jersey said in his opening statement Tuesday, included a commitment to find funding for energy infrastructure programs that would accelerate the replacement of aging, leaky pipelines and upgrade outdated electricity transmission lines, which also did not come to pass.

“This bill only aims to help polluters. Meanwhile, it continues to ignore the impacts of climate change, which remain the biggest threat




to our energy security and way of life,” Pallone said.Upton, on the other hand, remained optimistic that the bill, which

would be the first comprehensive energy bill since 2007, could make it to the President’s desk and be signed into law.

“While it has been difficult to find bipartisan consensus on as many fronts as I would have liked, I believe we have written a substantive, thoughtful bill,” he said.

The bill retains numerous bipartisan measures that would speed natural gas pipeline permitting, bolster grid resilience and mandate studies and dialogue to improve energy security and collaboration with nearby countries.

Other consensus measures in the bill include a provision allowing power plants to comply with must-run orders from DOE and not be open to liability under environmental law as well as a directive for FERC to create an Office of Compliance Assistance that would offer recommendations on consumer protection and market integrity and provide compliance guidance to regulated entities.

These and other provisions were not enough to sway most Democrats to vote in favor of the bill as a whole.

Democrats blasted a provision giving DOE 30 days from the completion of the National Environmental Policy Act review for an LNG export terminal to issue a public interest determination of the project’s exports. House Democrats have argued that such a deadline was arbitrary and would needlessly truncate DOE’s public interest reviews, disrupting the department’s existing approval process for LNG export applications.

inadequate funding to upgrade pipelines: democratsDemocrats were also infuriated that Republicans failed to put

adequate funding in place to modernize the country’s network of pipelines and transmission lines.

California Democrat Anna Eshoo called out Republicans for giving “lip service” to the need to repair and replace pipelines and upgrade transmission facilities but failing to put forth the funding when it counts.

Upton, who did support an amendment that passed to provide $100 million for gas pipeline replacements, said he could not support larger funding commitments at this time. He committed to working in good faith to determine if more funding might be made available once the House and Senate energy bills are converged.

Other contentious issues that pit Democrats against Republicans included a reliability analysis for proposed and final regulations costing more than $1 billion and a study of capacity markets that Democrats worried would force independent system operators and regional transmission organizations to accept Republicans’ narrow definition of reliability that they believe is skewed toward nuclear and coal generation.

Representative Michael Doyle, Democrat-Pennsylvania, said during Wednesday’s markup that a major factor in Democrats’ opposition to the bill was that 110 pages were added to it just 24 hours ago.

“Many of us just haven’t had the time to digest what’s in this bill and what it means. I think we find ourselves in a situation where we’re reluctant to support any of these provisions without having a chance first to discuss them,” he said.

“If this bill has any chance of becoming law — and as it’s written right now it doesn’t — sometime between this markup and when this bill gets some floor action, we need a chance to sit down and discuss some of the ways we can amend this bill to make sure that it meets the real reliability concerns that we all share,” Doyle added.

— Jasmin Melvin

ePa announces power plant water regulationThe Environmental Protection Agency today finalized regulations related to the discharge of toxic pollutants into waterways by steam electric plants.

The rules, known as the Steam Electric Effluent Limitation Guidelines, seek to reduce discharge of mercury, arsenic, lead and selenium, among other pollutants, by 1.4 billion pounds annually and decrease water withdrawal by 57 billion gallons per year.

The standards will require investments from 134 plants, which equates to about 12% of steam electric facilities in the US, according to the EPA. Oil-fired and plants with capacity of less than 50 MW are exempt from the rule. The standards will be phased in over time.

With nearly 16,000 MW of electric steam generation, FirstEnergy could be among the companies most impacted.

“While we are currently reviewing the regulation released today by EPA, FirstEnergy believes it is well-positioned to meet the new requirements for fly ash, since they address water discharges from wet transport of fly ash and all of FirstEnergy’s fly ash transport is dry. FirstEnergy continues to review other aspects of the rule as we await additional technical documents that EPA typically provides,” said Sephanie Walton, a FirstEnergy spokeswoman.

“These cost-effective, achievable limits will provide significant protections for our children and communities across the country,” said EPA Administrator Gina McCarthy.

— Matthew Eversman

transmission, generation often conflict: panelistsThe Houston Import Project flap has highlighted Electric Reliability Council of Texas’ generation and transmission owners’ competing interests, and attendees of a regional trade conference on Wednesday received a thorough briefing — but no resolution — of the issues involved.

The Houston Import Project is a 345-kV line that would connect a substation in the southeastern part of the Electric Reliability Council of Texas’ North Hub to a substation in northwest Harris County in ERCOT’s Houston Hub.

On April 24, Cross Texas Transmission and CenterPoint Energy Houston Electric applied for certificates of convenience and necessity to build the project, which links the eastern corner of Limestone County near Jewett, Texas, through Singleton, Texas, to a substation west of Tomball, Texas (Public Utility Commission of Texas projects 44649 and 44547). CenterPoint is the electricity transmission and distribution service provider for most of the Houston area.





On July 22, Calpine and NRG Energy filed testimony challenging the applications, arguing that ERCOT’s recommendation in favor of the Houston Import Project was outweighed by defects in the ERCOT analysis and an inappropriate exercise of its discretion in the matter.

On September 23, the PUC staff submitted a proposed order approving a certificate of convenience and necessity for the project, on which the PUC has not yet acted.

It was with the backdrop of this case that Ross Baldick, a University of Texas professor of electrical and computer engineering, moderated a panel discussion entitled “Changing currents in transmission” at the Gulf Coast Power Association’s Fall Conference in Austin, Texas.

“Almost inevitably, there’s a tension between” largely regulated transmission interests and relatively deregulated generation interests, Baldick said, introducing the subject.

“How do we get those competing forces to play well?” he asked.One option would be for transmission to be built according to a

model of building transmission first and with generation following, Baldick said. Such a plan was used in the Competitive Renewable Energy Zone project, a set of transmission projects that cost about $6.9 billion, designed to bring West Texas wind power to the population centers in the eastern half of Texas.

An alternative would be to allow generation to be built wherever developers can do so and build transmission to link those power sources to the users of power, he said.

However, the latter option has a temporal problem, Baldick noted.

long lead time for wires projects“The time to build transmission tends to be longer than that to

build, let’s say, a wind farm or combined-cycle generator,” Baldick said.

Judy Chang, a Brattle Group principal consultant in the panel discussion, said one factor to consider is whether the federal Clean Power Plan is upheld in court.

“We are at the cusp and juncture of great uncertainty — probably the greatest uncertainty we have seen since deregulation,” Chang said. “We need to think about how to incorporate those uncertainties in that long-term [transmission] planning.”

For example, other parts of the US look upon the CREZ projects as an approach that “actually works,” Chang said.

Another panelist was Liz Jones, director of regulatory affairs at Oncor, the state’s largest transmission and distribution provider, who provided a different perspective.

“Planners want the best intelligence we can get for resources and load,” Jones said, “[but the entities that represent resources and load] are really not interested in talking to us for valid competitive reasons.”

This occasionally results in a big disconnect between plans and reality, she said. For example, CREZ lines were built to supply western power to eastern load centers, she said.

“Then, lo and behold, along came the fracking explosion and we find ourselves exporting power on an east-to-west basis,” Jones said.

‘obligation to serve load’Such a circumstance is heavily influenced by the different regulatory

burdens faced by transmission and generation entities, she said.

“Wires companies retain the obligation to serve load, and generation does not,” Jones said. “When in doubt, we build more, not less.”

However, another panelist, Randa Stephenson, Lower Colorado River Authority vice president for wholesale markets, said, “As wholesale [energy] prices have been decreasing, you have seen an increase in the distribution-cost component of the retail bill.”

Furthermore, the market cannot afford to spend “$100 million to get the last megawatt of deliverability from every generator,” Stephenson said.

Bob King, president of Good Company Associates, which consults on environmental and regulatory issues, asked how distributed generation might minimize the need for transmission.

Jones said transmission providers could more easily incorporate distributed generation into the market if it were “spread like peanut butter across a load zone.”

“But even if it were spread like peanut butter, it would be really chunky peanut butter,” Jones said.

Chang said, “There’s no doubt that distributed generation will increase ... but that doesn’t necessarily mean a dramatic decrease in the need for transmission.”

“California probably has the largest concentration of distributed solar in the country,” Chang said. “They are now looking at transmission to the rest of the West and thinking about what happens when you have too much solar. It’s not a simple equation.”

— Mark Watson

dP&l auction continues price trend in ohioOhio wholesale power prices continued their overall decline over the past year as reflected by Dayton Power & Light’s latest descending clock auction results approved Wednesday by the Ohio Public Utilities Commission.

DP&L’s auction on Monday resulted in an average clearing price of $51.49/MWh for 40% of the AES Corp. subsidiary’s standard service offer load for the delivery period January 2016 through May 2017.

During the 15-round auction, six competitive suppliers submitted winning bids for the opportunity to provide electricity to DP&L’s SSO customers.

Under commission policy, the winners will not be publicly identified for 21 days.

In recent Ohio auctions, AEP Energy Partners and Exelon Generation, competitive units of Columbus, Ohio-based American Electric Power and Exelon, headquartered in Chicago, have captured a large number of available tranches.

Thirteen bidders registered for the DP&L auction that had a starting price of $90 to $120/MWh, according to a report submitted to the commission by CRA International, DP&L’s independent auction manager. Boston Pacific, a PUC consultant, monitored the auction process.

There was a sealed-bid round, CRA added.The latest results will be blended with two previous auctions to

determine DP&L’s retail generation service rates through May 2017.DP&L’s Monday auction cleared considerably below the average

clearing price of $62.08/MWh in the utility’s auction in September 2014.




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DP&L is Ohio’s smallest investor-owned electric utility, serving about 500,000 customers in the west-central part of the state.

Since last September, several other Ohio utilities have held similar SSO auctions, including AEP, Duke Energy and FirstEnergy.

FirstEnergy’s October 2014 auction cleared at the highest price during the past year, $73.82/MWh. That was followed by a lower $69.18/MWh clearing price in the Akron-based company’s January 2015 competitive bidding process.

Duke’s lone auction so far in 2015, in May, cleared in a range of $58.79/MWh to $59.17/MWh. Duke plans to conduct another auction in November.

AEP, meanwhile, held two auctions during a two-week period in April and May this year. Clearing prices for those auctions ranged from $53.51/MWh to $55.58/MWh in April to $54.42/MWh to $56.35/MWh in May.

During the past year, more than 6,000 MW of older coal-fired generation capacity have been shuttered in Ohio, mainly by AEP and FirstEnergy. To date, though, the retirements do not appear to have exerted any positive impact on power prices.

Paul Patterson, a Glenrock Associates energy analyst in New York, said that, in general, the potential for coal plant closures had been anticipated by the market for some time.

As a result, he said, “I don’t think one should expect that the actual retirements of older coal-fired units to have that substantial an impact on the forward markets at this point in time, particularly when one

considers the new generation in development and anemic power demand growth.”

In Ohio, four new natural gas plants totaling more than 3,000 MW of generation are in construction and development, with more anticipated.

The DP&L auction kicked off a multi-month stretch of important events likely to shape Ohio’s electric market for years.

In addition to the upcoming Duke auction, the PUC is holding hearings on controversial power purchase agreement proposals by AEP and FirstEnergy covering more than 6,000 MW of coal and nuclear generation in the state.

Once the commission rules late this year or in early 2016, there should be more clarity about whether Ohio’s decade-and-a-half experiment with electric deregulation will continue, or if the state will return to at least some form of re-regulation.

— Bob Matyi

dFax seen as wrong approach to cost allocationRate filings allocating costs for two regional transmission upgrade projects within PJM Interconnection should be rejected or at the very least set for hearing, companies and state regulators said in filings with the Federal Energy Regulatory Commission Monday.

Protests challenging proposed amendments to PJM’s tariff to incorporate cost allocations for the Artificial Island (ER15-2563) and


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