Megawatt Daily

8/20/2019 Megawatt Daily

1/20

www.platts.com

[ELECTRIC POWER

Wednesday, October 7, 2015

MEGAWATT DAILYwww.twitter.com/plattspower

Inside this Issue

Wind, ‘dirt cheap’ gas stifle Central power prices 12

Michigan PSC study touts energy efficiency savings 13

NV Energy lowers rates as wholesale prices fall 14

Oncor deal, ERCOT fee hike on PUC agenda 15

EIA forecasts drop in winter heating expenditure 15

Low and high average day-ahead LMP for Oct 7 ($/MWh)

On-peak low On-peak high Off-peak low Off-peak high

ISONE 39.44 41.53 23.58 24.06

NYISO 18.17 50.29 8.96 28.22

PJM 27.86 44.86 20.44 26.88

MISO 24.06 36.92 13.63 22.80

ERCOT 25.27 28.50 15.12 15.51

SPP 21.27 27.18 14.35 19.51

CAISO 35.89 38.25 26.93 27.36

Note: Lows and highs for each ISO are for various hubs and zones. A full listing of averageLMPs are available for the hubs and zones inside this issue.

Day-ahead bilateral indexes and spark spreads for Oct 7

Marginal Spark spreads

Index heat rate @7k @8k @10k @12k @15k

Southeast

Southern, Into 28.00 12056 11.74 9.42 4.78 0.13 -6.84

Florida 34.00 14719 17.83 15.52 10.90 6.28 -0.65

Northwest

Mid-C 23.46 10603 7.97 5.76 1.34 -3.09 -9.73

COB 24.98 10744 8.71 6.38 1.73 -2.92 -9.90

Southwest

Palo Verde 23.68 10120 7.30 4.96 0.28 -4.40 -11.42

Mead 26.50 10950 9.56 7.14 2.30 -2.54 -9.80

Note: All indexes are on-peak. Spark spreads are reported in ($) and Marginal heat rates in

(Btu/kWh). A full listing of bilateral indexes and marginal heat rates are inside this issue.

Price trends at key trading points ($/MWh)

Source: Platts

10

20

30

40

50

60

07-Oct01-Oct25-Sep19-Sep13-Sep07-Sep

SP15

ERCOT North

Indiana Hub

PJM West

ISONE Hub

District of Columbia Mayor Muriel Bowser said

Tuesday Washington DC has reached an agreement

with Exelon in the Chicago company’s quest to merge with Pepco

Holdings that includes a $78 million investment in the capital

city, five times more than originally offered.

Bowser said during a news briefing that she kept the

negotiations with Exelon alive after the Public Service

Commission rejected the initial offer in hopes of reaching an

agreement that put DC ratepayers first.

The deal promotes sustainability, energy efficiency and the

development of solar and wind generation, initiatives that those

opposing the deal said would fall by the wayside if a generation

company took over the purely distribution DC utility.

The agreement includes $17 million to further the energy

DC, Exelon reach agreement for Pepco merger

(continued on page 17)

Spark spread movements have varied by region

following a drop in both gas and power prices as factors

like renewables and weather have impacted margins earned by

generators.

Based on gas and power prices at 13 major electricity

trading hubs across the US, the simple average October spark

spread is down $5.17/MWh from September and $10.51/MWhfrom August.

Power prices at those hubs year to date have averaged about

$40/MWh, down 35% from the same period in 2014.

Henry Hub natural gas prices have averaged $2.78/MMBtu year

to date, 39% below the same period in 2014. Prices there recently

hit their lowest level since early 2012, $2.26/MMBtu.

Spark spreads vary amid drop in power prices


The PJM Interconnection’s markets and reliability

committee have been asked to consider taking action

to resolve problems with the penalties built into the grid

operator’s capacity performance rules.Robert O’Connell, a consultant who represents a group of

generation developers, transmission owners and others has

proposed allowing generation owners who have units that over

perform during a capacity performance period and units that

underperform to offset each other without incurring a penalty.

“It’s a way to use a generation portfolio to manage the risk of

underperforming,” O’Connell said Tuesday in an interview. He

calls it portfolio netting.

Penalties can be high, up to $1,800/MWh plus another $3,500/

MWh under certain circumstances if a unit trips, without much

Generators lobby for ‘portfolio netting’ rule


MARKETDESIGN

MERGERS

BENTEKANALYSIS


2/20

WEDNESDAY, OCTOBER 7, 2015MEGAWATT DAILY

2 Copyright © 2015 McGraw Hill Financial

Northeast load and generation mix forecast (GWh)

Actual % Chg Forecast 05-Oct %Chg Year-ago 06-Oct 07-Oct 08-Oct 09-Oct 10-Oct

ISONE

Load 313 12 1 341 334 316 308 282

Generation

Coal 3 688 28 5 6 5 5 5

Gas 149 12 11 163 157 141 130 122Nuclear 46 0 -10 46 48 56 68 81

NYISO

Load 420 23 2 409 404 400 398 362

Generation

Coal 11 58 -24 11 11 11 11 12

Gas 125 -4 25 154 148 136 132 124

Nuclear 135 0 6 135 135 135 135 135

Source: Bentek

Northeast spot natural gas prices ($/MMBtu)

Source: Platts

1

2

3

4

5

6

06-Oct28-Sep18-Sep10-Sep01-Sep24-Aug

Iroquois zone 2 Transco zone 6 N.Y. Algonquin city-gates

ISONE & NYISO nuclear generation outages (GW)

Source: NRC

0

500

1000

1500

2000

2500

3000

6-Oct21-Sep6-Sep22-Aug7-Aug23-Jul8-Jul

2015 2014 2013

NORTHEAST MARKETS

Mass Hub steady in mid-$30s/MWhNortheast dailies were mixed Tuesday amid stable demand

projections and higher spot natural gas prices.

Mass Hub on-peak prices for Wednesday delivery tacked on 75

cents to about $35.50/MWh on the IntercontinentalExchange.

Mass Hub day-ahead off-peak slipped $1.25 to about $23.75/

MWh, however.

The ISO New England predicted demand to peak at around

15,350 MW both Tuesday and Wednesday before slipping to

about 14,825 MW Thursday.

Algonquin Gas Transmission city-gates spot gas climbed 6.3

cents to $2.953/MMBtu.

Boston temperatures were forecast about 5 degrees above

average Wednesday, with a high of 71 degrees expected.

Daily locational marginal prices were higher across New York

as both spot gas prices and demand outlook rose amid above-

average temperature forecasts.

New York ISO Zone G Hudson Valley day-ahead on-peak LMPs

gained $1.75 to around $34.25/MWh for Wednesday delivery.

Zone J New York City day-ahead on-peak rose $2.25 to roughly

$34.75/MWh. Zone A West day-ahead on-peak was about $40.25

after climbing $9.25.

Transco Zone 6 New York spot natural gas rose 11.7 cents to

$2.397/MMBtu, helping to support power prices.

The New York ISO predicted peakload near 18,500 MW

Tuesday, 18,650 MW Wednesday and 18,450 MW Thursday.

Temperature highs in New York state were forecast as much as

8 degrees above normal in the mid-60s to mid-70s Wednesday.

Northeast term power was mixed Tuesday afternoon as bothNYMEX gas futures and regional gas basis strengthened.

In New England, Mass Hub on-peak November fell 50 cents to

$56.50/MWh on the IntercontinentalExchange around 2:30 pm

EDT. Mass Hub on-peak December added 25 cents to around $69/

MWh, while the on-peak January-February contract lost 25 cents

to $89.25/MWh.

In New York, Zone G on-peak November financial futures

dropped more than 50 cents to $45/MWh. Zone A on-peak

November added 25 cents to $35.75/MWh on ICE, still nearly $10

below contract prices seen in October 2014.

NYMEX November gas futures tacked on 2 cents to around

$2.47/MMBtu. Algonquin city-gate November gas basis edged up

0.7 cents to $2.858/MMBtu and Transco Zone 6 NY November gasbasis gained 5 cents to 20 cents/MMBtu.

Daily generation outage references

MO unplanned maintenance outage RF refueling outagePMO planned maintenance outage Unk unknownOA offline/available

Fuels: Nuclear=n; Coal=c; Natural gas=g; Hydro=h ; Wind=wSources: Generation owners, public information and other market sources.


3/20



N.Y. Zone G: Marginal heat rate on-peak (Btu/kWh)

15000

20000

25000

30000

35000

06-Oct28-Sep18-Sep10-Sep2-Sep

Month 1

Month 2

N.Y. Zone G: Forward curve on-peak ($/MWh)

0

20

40

60

80

100

C a l - 1

9

C a l - 1

8

C a l - 1

7

C a l - 1

6

Q 4

- 1 7

J u l / A u g

- 1 7

M a r

/ A p r - 1 7

J a n / F e b

- 1 7

S e p

- 1 7

J u n

- 1 7

M a y - 1

7

Q 4

- 1 6

J u l / A u g

- 1 6

M a r

/ A p r - 1

6

J a n / F e b

- 1 6

S e p

- 1 6

J u n

- 1 6

M a y - 1

6

J a n

- 1 6

D e c - 1 5

N o v - 1

5

ISONE day-ahead LMP for Oct 7 ($/MWh)

Avg Marginal

Hub/Zone Average Cong Loss Change $/Mo heat rate

On-peak

Internal Hub 41.31 0.00 0.17 6.20 31.51 14542

Connecticut 41.30 0.00 0.15 6.41 31.34 14686

NE Mass-Boston 41.53 0.00 0.38 6.24 31.79 14618

SE Mass 41.05 0.00 -0.10 6.12 31.45 14449West-Central Mass 41.44 0.00 0.29 6.25 31.56 14587

Rhode Island 40.91 0.00 -0.24 6.05 31.59 14400

Maine 39.44 -0.03 -1.68 5.70 30.71 14446

New Hampshire 41.24 -0.01 0.11 6.23 31.57 15106

Vermont 41.24 0.00 0.09 6.10 31.20 15103

Off-Peak

Internal Hub 23.99 0.00 0.06 -6.13 20.85 8365

Connecticut 23.87 0.00 -0.06 -6.13 20.77 8336

NE Mass-Boston 24.05 0.00 0.12 -6.13 20.93 8386

SE Mass 23.87 0.00 -0.06 -6.26 20.83 8323

West-Central Mass 24.06 0.00 0.13 -6.12 20.88 8388

Rhode Island 23.95 0.00 0.02 -5.92 20.79 8350

Maine 23.58 0.00 -0.35 -5.87 20.42 8582

New Hampshire 24.00 -0.01 0.08 -6.04 20.78 8736

Vermont 23.68 0.00 -0.25 -6.12 20.50 8618

NYISO day-ahead LMP for Oct 7 ($/MWh)

Avg Marginal


On-peak

Capital Zone 33.27 0.00 1.42 1.57 27.22 15338

Central Zone 32.65 -0.54 0.26 1.78 26.40 20942

Dunwoodie Zone 34.19 0.00 2.35 1.72 28.15 13155

Genesee Zone 31.95 0.03 0.13 1.40 25.96 20494

Hudson Valley Zone 34.20 0.00 2.35 1.71 28.10 13157

Long Island Zone 50.29 -15.09 3.36 16.67 33.99 19349

Millwood Zone 34.23 0.00 2.38 1.75 28.15 13169

Mohawk Valley Zone 31.04 0.84 0.03 0.62 25.90 16818

N.Y.C. Zone 34.78 -0.40 2.53 2.16 29.19 13379

North Zone 18.17 6.43 -7.25 -5.20 19.35 6657

West Zone 40.24 -7.50 0.90 9.28 27.47 25814

Off-Peak

Capital Zone 25.96 -3.88 0.96 5.29 17.76 11844

Central Zone 21.64 -0.47 0.06 1.53 16.31 13806

Dunwoodie Zone 25.45 -2.90 1.44 4.22 18.04 9839

Genesee Zone 21.42 -0.36 -0.06 1.44 16.12 13664

Hudson Valley Zone 25.42 -2.88 1.43 4.22 17.99 9826

Long Island Zone 28.22 -4.98 2.13 6.42 20.23 10908Millwood Zone 25.47 -2.92 1.44 4.28 18.02 9846

Mohawk Valley Zone 20.57 0.49 -0.06 0.83 16.05 11128

N.Y.C. Zone 25.58 -2.90 1.56 4.23 18.22 9888

North Zone 8.96 7.38 -4.78 -5.54 11.61 3261

West Zone 22.26 -0.66 0.49 1.86 16.47 14200

Generation unit outage report

Plant/Operator Cap Fuel State Status Return Shut

Northeast

Atikokan/OPG 205 bio Ont. MO Unk 09/29/15

Bruce-3/Bruce Power 780 n Ont. MO Unk 10/02/15

Bruce-4/BrucePower 780 n Ont. MO Unk 10/01/15

Darlington-1/OPD 881 n Ont. MO Unk 09/14/15




Goreway-11/SitheGoreway 195 g Ont. MO Unk 09/18/15

Lake Superior/Brookfield 120 g Ont. PMO Unk 11/04/14Lennox-3/OPG 525 g Ont. MO Unk 09/04/15

Lennox-4/OPG 525 g Ont. PMO Unk 09/28/15

Millstone-2/Dominion 870 n Conn. MO Unk 10/03/15

Pickering-6/OPG 520 n Ont. MO Unk 09/21/15

Seabrook-1/NextEra 1296 n N.H. RF Unk 10/01/15

Northeast Platts M2MS Forward Curve, Oct 6 ($/MWh)

Prompt month: Nov 15 On-peak Off-peak

Mass Hub 56.25 43.00

N.Y. Zone G 45.00 32.15

N.Y. Zone J 46.95 33.00N.Y. Zone A 35.55 22.50

Ontario* 20.65 12.90

*Ontario prices are in Canadian dollars


4/20



Southeast & Central day-ahead bilateral indexes for Oct 7 ($/MWh)

Avg Marginal

Index Change $/Mo heat rate

Southeast On-peak

VACAR 29.75 -1.25 29.55 12396

Southern, Into 28.00 -1.00 28.35 12056

GTC, Into 29.00 -1.50 29.15 10334

Florida 34.00 -1.00 34.35 14719

TVA, Into 29.00 -1.00 28.75 12147

Southeast Off-Peak

VACAR 22.75 0.50 20.29 9479

Southern, Into 23.00 1.75 21.43 9903

GTC, Into 24.00 1.75 22.21 10334

Florida 25.75 1.75 24.61 11147

TVA, Into 22.75 1.00 20.75 9529

Southeast load and generation mix forecast (GWh)


ERCOT

Load 960 19 3 938 958 969 928 843Generation

Coal 410 14 1 391 400 407 400 387

Gas 301 9 11 352 357 355 329 301

Nuclear 94 0 7 94 95 100 108 115

SPP

Load 621 7 0 616 632 651 614 561

Generation

Coal 360 -1 -7 357 359 361 351 341

Gas 127 55 13 127 124 119 99 87

Nuclear 61 -2 -3 61 61 61 61 61

Source: Bentek

Southeast & Central spot natural gas prices ($/MMBtu)

Source: Platts

2.00

2.25

2.50

2.75

3.00


Panhandle, Tx. Okla. Houston Ship Channel Henry Hub

ERCOT & SPP nuclear generation outages (GW)

Source: NRC

0

500

1000

1500

2000

2500


2015 2014 2013

SOUTHEAST MARKETS

ERCOT dailies down 41% from 2014 valuesElectric Reliability Council of Texas dailies lost ground Tuesday

despite rising demand expectations and stronger spot gas prices.

ERCOT North Hub day-ahead on-peak physical dropped $1 to

about $25.75/MWh for Wednesday delivery on the

IntercontinentalExchange. So far in October, day-ahead values are

down nearly 16% from September and are almost 41% below

October 2014 values. Off-peak lost $1.75 to around $16/MWh.

Balance-of-the-day on-peak for Tuesday traded at around $21.25/

MWh, down $5.50 from where the daily package traded Monday.

ERCOT North Hub balance-of-the-week on-peak fell $3 to $28/

MWh. Next-week on-peak was steady at $28/MWh.

Spot natural gas at Houston Ship Channel gained 2.1 cents to

about $2.361/MMBtu on ICE.

ERCOT forecast system load to peak around 48,550 MW

Tuesday, 52,325 MW Wednesday and 52,550 MW Thursday. Wind

generation was forecast to peak at 5,050 MW at midnight CDT

Tuesday and 5,625 MW at 1 am CDT Wednesday.

High temperatures across Texas were forecast in the upper 80s

to low 90s Wednesday, as much as 9 degrees above normal. Lows

were expected in the mid- to upper 60s, as much as 8 degrees

above normal.

Real-time prices showed no congestion by 2 pm CDT Tuesday

and averaged $18/MWh, down $1.25 from the same time

Monday.

In the Southeast, dailies were weaker Tuesday as temperatures

were forecast above seasonal norms.

Into Southern day-ahead on-peak physical power eased about

$1 to the upper $20s/MWh for Wednesday delivery on ICE. So farin October, Into Southern day-ahead prices are down 7% from

September and are about 27% below the October 2014 average

value.

Spot natural gas at Transco Zone-3 added 3.3 cents to about

$2.333/MMBtu on ICE.

High temperatures in Atlanta were forecast at 84 Wednesday, 9

degrees above normal. Lows were expected at 62, 5 degrees above

normal.

ERCOT forwards were mixed Tuesday as NYMEX November

gas futures added 2 cents to about $2.47/MMBtu, holding steady

with morning activity.

ERCOT North Hub November on-peak rose 25 cents to $24.75/

MWh on the Intercontinental Exchange around 2:30 pm EDT.December on-peak lost 25 cents to $25.25/MWh. January-February

and March-April on-peak were flat to each other at $28.75/MWh.

May on-peak was steady at $27.25/MWh. June on-peak stayed

near $33/MWh. July-August on-peak jumped $1.25 to $53.75/

MWh. July-August 2018 on-peak heat rates traded 50 MW at 19.50

MMBtu/MWh.

In the Southwest Power Pool, SPP North Hub November

on-peak gained about 25 cents to $22/MWh and SPP South Hub

November on-peak was steady around $27.50/MWh.


5/20



ERCOT South: Marginal heat rate on-peak (Btu/kWh)

9000

10000

11000

12000

13000


Month 1

Month 2

ERCOT South: Forward curve on-peak ($/MWh)

0

10

20

30

40

50

60

C

a l - 1 9

C

a l - 1 8

C

a l - 1 7

C

a l - 1

6

Q

4 - 1 7

J u l / A

u g - 1 7

M a r / A

p r - 1 7

J a n / F

e b - 1 7

S e p

- 1 7

J u n

- 1 7

M a y

- 1 7

Q

4 - 1 6

J u l / A

u g - 1

6

M a r / A

p r - 1

6

J a n / F

e b - 1

6

S e p

- 1 6

J u n

- 1 6

M a y

- 1 6

J a n

- 1 6

D e c

- 1 5

N o v

- 1 5

ERCOT average day-ahead LMP for Oct 7 ($/MWh)

Avg Marginal

Hub/Zone Average Change $/Mo heat rate

On-peak

Bus Average 25.68 -0.42 24.14 11174

Hub Average 25.91 -0.33 24.35 11274

Houston Hub 26.85 -0.15 25.26 11383

North Hub 25.29 -0.56 23.76 11135South Hub 26.02 -0.19 24.40 11267

West Hub 25.49 -0.43 23.98 11302

AEN Zone 25.80 -0.40 24.38 11441

CPS Zone 26.80 -0.01 25.47 11600

LCRA Zone 27.08 0.72 24.63 11723

Rayburn Zone 25.27 -0.52 23.74 11127

Houston Zone 27.50 -0.15 25.80 11660

North Zone 26.05 -0.55 24.20 11468

South Zone 28.50 -0.21 26.17 12336

West Zone 27.41 -2.41 25.58 12157

Off-Peak

Bus Average 15.21 -1.67 16.18 6703

Hub Average 15.27 -1.63 16.20 6727

Houston Hub 15.51 -1.48 16.29 6636

North Hub 15.12 -1.71 16.13 6825

South Hub 15.30 -1.64 16.24 6679West Hub 15.15 -1.69 16.14 6773

AEN Zone 15.24 -1.61 16.14 6815

CPS Zone 15.30 -1.76 16.40 6680

LCRA Zone 15.26 -1.65 16.18 6661

Rayburn Zone 15.12 -1.71 16.13 6824

Houston Zone 15.50 -1.50 16.29 6631

North Zone 15.12 -1.71 16.13 6826

South Zone 15.36 -1.65 16.31 6704

West Zone 15.16 -1.69 16.15 6777

MISO South average day-ahead LMP for Oct 7 ($/MWh)

Avg Marginal


On-peak

Arkansas Hub 29.47 -1.14 -1.26 -0.33 26.83 13153Louisiana Hub 36.92 5.06 0.00 2.51 29.48 16241

Texas Hub 34.03 2.28 -0.11 1.40 29.42 14443

Off-Peak

Arkansas Hub 20.26 0.87 -0.43 0.23 19.05 9071

Louisiana Hub 20.64 0.76 0.06 -0.14 19.53 9129

Texas Hub 20.67 0.87 -0.01 -0.31 19.71 8843

SPP average day-ahead LMP for Oct 7 ($/MWh)

Avg Marginal


On-peak

SPP North Hub 21.27 -1.60 -1.36 -1.55 19.40 8982

SPP South Hub 27.18 2.07 0.89 0.32 25.06 12290

Off-PeakSPP North Hub 14.35 -1.40 -1.16 -0.56 13.99 6158

SPP South Hub 19.51 2.09 0.51 -1.01 18.96 8904

Southeast near-term bilateral markets ($/MWh)

Package Trade date Range

Southern, into

Bal-month 10/01 27.75-28.25



Southeast & Central

Arkansas-2/Entergy 1065 n Ark. RF Unk 09/20/15

Big Brown/Luminant 575 c Texas MO Unk 04/13/15

Bowen-2/Georgia Power 800 c Ga. PMO Unk 04/04/13

Comanche Peak-2/Luminant1250 n Texas RF Unk 10/03/15

Fermi-2/DTE 1131 n Mich. MO Unk 09/13/15

Limestone-2/NRG 860 c Texas MO Unk 08/09/14

Martin Lake-2/Luminant 750 c Texas MO Unk 02/01/15

Martin Lake-3/Luminant 750 c Texas MO Unk 06/18/15McGruire-2/Duke 1156 n N.C. MO Unk 09/12/15

Monticello-1/Luminant 565 c Texas MO Unk 06/18/15

Monticello-2/Luminant 565 c Texas MO Unk 06/11/14

Saint Lucie-2/FP&L 1002 n Fla. MO Unk 09/07/15

Summer/SCE&G 1006 n S.C. RF Unk 10/02/15

Vogtle-1/Southern Nuclear 1213 n Ga. RF Unk 09/20/15

WattsBar-1/TVA 1210 n Tenn. PMO Unk 09/20/15

Southeast & Central Platts M2MS Forward Curve, Oct 6 ($/MWh)


Southern Into 33.85 27.05

Entergy Into 31.45 27.30

ERCOT North 24.80 19.25ERCOT Houston 25.85 19.95

ERCOT West 24.40 17.50ERCOT South 25.15 18.00


6/20



Western day-ahead bilateral indexes for Oct 7 ($/MWh)

Avg Marginal

Index Change $/Mo heat rate

On-peak

Mid-C 23.46 -0.62 23.25 10603

John Day 24.50 -0.50 24.29 11073

COB 24.98 -1.32 25.56 10744

NOB 25.00 -1.00 25.38 11299

Palo Verde 23.68 -1.42 25.61 10120Westwing 24.50 -1.00 26.79 10470

Pinnacle Peak 23.50 -1.50 26.17 10043

Mead 26.50 -1.25 27.54 10950

Mona 25.00 1.00 25.67 11390

Four Corners 24.00 -0.75 26.38 10619

Off-Peak

Mid-C 21.38 -2.20 22.13 9663

John Day 22.50 -2.00 23.18 10169

COB 22.44 -1.10 22.72 9652

NOB 23.00 -1.75 23.54 10395

Palo Verde 20.31 -0.59 21.29 8679

Westwing 20.75 -0.50 21.57 8868

Pinnacle Peak 20.50 -0.50 21.71 8761

Mead 21.50 -0.50 22.04 8884

Mona 20.75 -1.25 21.82 9453

Four Corners 19.75 -0.25 19.82 8739

Western load and generation mix forecast (GWh)


CAISO

Load 649 21 -4 633 655 670 690 652

Generation

Gas 269 3 -7 250 253 266 285 306

Nuclear 28 0 11 28 29 33 41 48

Source: Bentek

Western spot natural gas prices ($/MMBtu)

Source: Platts

1.5

2.0

2.5

3.0

3.5

4.0


NW, Can. Bdr. (Sumas) SoCal Gas ci ty-gate PG&E city-gate

CAISO nuclear generation outages (GW)

Source: NRC

0

2000

4000

6000

8000

27-Feb12-Feb28-Jan13-Jan29-Dec14-Dec29-Nov

2015 2014 2013

WEST MARKETS

SP15 values inch up in mid-$30s/MWhWest day-ahead on-peak prices were mixed Tuesday as

California prices edged up with the drop in nuclear generation

weighing on the market and demand set to go up slightly midweek.

The planned outage at the 1.1 GW Diablo Canyon unit-1

reduced nuclear generation in the Southwest to 1.1 GW on

Sunday, down from 2 GW on Saturday. Thermal generation

jumped to 13 GW on Monday, from 9.9 GW on Sunday.

In California, SP15 day-ahead on-peak was up 25 cents to

about $35.25/MWh. Off-peak was flat at about $27.50/MWh.

The California ISO projected peak demand at about 31,375

MW Tuesday and 32,850 MW Wednesday.

The spot natural gas price for Wednesday delivery in Southern

California declined with Socal city-gate down 2 cents to about

$2.619/MMBtu.

In the Southwest, Palo Verde day-ahead on-peak for

Wednesday delivery was down $1.50 to around $23.75/MWh on

ICE. Day-ahead off-peak was down 50 cents to about $20.50/MWh.

Phoenix high temperatures were expected at 87 degrees on

Wednesday, 5 degrees below the average. In Las Vegas, highs were

expected to reach 88 degrees on Tuesday, 3 degrees above the norm.

Arizona gas-fired power demand averaged 1 Bcf/d on Monday,

down from 1.03 Bcf/d on Sunday. Nevada gas burn averaged 424

MMcf/d from 430 MMcf/d over the same period, according to data

from Bentek Energy.

In the Northwest, Mid-Columbia day-ahead on-peak was down

50 cents to around $23.50/MWh. Off-peak was down $2 around

$21.75/MWh.

Portland’s high temperature was forecast at 72 degrees onWednesday, 5 degrees above the norm. Seattle was forecast to see

a high of 68 degrees, 6 degrees higher than the average.

BPA net exports averaged 102 GWH/d on Monday, up 17%

from the day before. Month to date, exports have averaged 112

GWh/d, up from 99 GWh/d from the same period a year ago.

Western US forward prices were little changed Tuesday as

NYMEX November gas futures edged up. NYMEX November gas

futures rose 2 cents to $2.47/MMBtu.

In California, SP15 on-peak November fell 25 cents to about

$33.25/MWh on IntercontinentalExchange at about 2:30 pm EDT

and 75 MW traded on-screen. First quarter on-peak rose 25 cents

to about $33.75/MWh.

Socal gas basis November was at 6.5 cents, up 0.25 cent fromMonday.

In the Northwest, Mid-Columbia on-peak November was flat

at $24.50/MWh.

NWP-Sumas November gas basis was at minus 18 cents, up

0.75 cent from Monday.

Mid-C off-peak November fell 50 cents to about $21.25/MWh.

On-peak December was up 25 cents to about $29.50/MWh. First

quarter on-peak was up 25 cents to about $24.50/MWh.

In the Southwest, Palo Verde on-peak November was up 25

cents to about $25.50/MWh.


7/20



NP15: Marginal heat rate on-peak (Btu/kWh)

10000

11000

12000

13000

14000


Month 1

Month 2

NP15: Forward curve on-peak ($/MWh)

0

10

20

30

40

50

C

a l - 1

9

C

a l - 1

8

C

a l - 1

7

C

a l - 1

6

Q

4 - 1 7

Q

3 - 1 7

Q

2 - 1 7

Q

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Q

4 - 1 6

Q

3 - 1 6

Q

2 - 1 6

Q

1 - 1 6

J a n - 1 6

D e c - 1 5

N o v - 1 5

CAISO average day-ahead LMP for Oct 7 ($/MWh)

Avg Marginal


On-peak

NP15 Gen Hub 38.25 1.13 -0.85 1.80 34.08 13089

SP15 Gen Hub 35.89 -0.70 -1.38 1.55 33.32 14814

ZP26 Gen Hub 36.13 -0.15 -1.69 1.40 32.97 14912

Off-PeakNP15 Gen Hub 27.36 -0.01 -0.52 -0.97 27.61 9361

SP15 Gen Hub 27.01 -0.03 -0.85 -0.92 27.37 11140

ZP26 Gen Hub 26.93 0.00 -0.96 -0.99 27.18 11109

Western near-term bilateral markets ($/MWh)

Package Trade date Range

Mid-C

Bal-week 10/06 22.25-22.75

Bal-week 10/05 24.25-24.75

Bal-week 10/02 23.00-23.50

Bal-week 09/30 22.75-23.25

Bal-month 10/06 23.25-23.75

Bal-month 10/05 23.50-24.00

Bal-month 10/02 22.50-23.00Bal-month 10/01 22.50-23.00

Bal-month 09/30 24.00-24.50

Bal-month (off-peak) 10/06 21.00-21.50





Next-week 10/06 23.50-24.00

Next-week 10/05 23.75-24.25

Next-week 10/02 22.75-23.25

Next-week 10/01 23.25-23.75

Next-week 09/30 25.75-26.25

Next-week (off-peak) 10/06 22.25-22.75



Palo Verde

Bal-month 10/05 27.50-28.00Bal-month 10/02 27.50-28.00

Bal-month 10/01 27.00-27.50




West

Belden Hydro/PG&E 119 h Calif. MO Unk 10/05/15

Big Creek Hydro/SCE 820 h Calif. PMO Unk 10/05/15

Diablo Canyon-1/PG&E 1150 n Calif. PMO Unk 10/04/15

Helms Pump-1/PG&E 407 h Calif. PMO Unk 09/27/15

Inland-2/Inland Empire 366 g Calif. MO Unk 09/22/15

Mariposa Energy/PG&E 196 g Calif. MO Unk 10/05/15

Middle Fork-Ralston/PG&E 218 h Calif. MO Unk 10/01/15

Mountainview-3/MPC 525 g Calif. PMO Unk 10/04/15

Patterson/PG&E 138 w Calif. MO Unk 10/04/15

Pine Flat/CDWR 210 h Calif. MO Unk 08/23/15

Pittsburg-5/Mirant 312 g Calif. PMO Unk 10/01/15

Western Platts M2MS Forward Curve, Oct 6 ($/MWh)


Mid-C 24.60 21.20

Palo Verde 25.10 20.70

Mead 26.00 21.85NP15 36.05 28.95

SP15 33.20 27.70

BPA & CAISO hydro and wind generation (GWh)

Source: BPA and CAISO

0

50

100

150

200

5-Oct30-Sep25-Sep20-Sep15-Sep10-Sep5-Sep

CAISO WindBPA WindCAISO HydroBPA Hydro

Additional information on data and analysis

For more information on data and analysis from Bentek Analytics, includingfive-day load and generation mix forecasts and relative load normalizedby temperature, email [email protected], or call 303-988-1320.Average on-peak and off-peak LMP and marginal heat-rate data is availablevia Platts Market Data. More detailed, hourly LMP and marginal heat-ratedata is available from Bentek Analytics.


8/20



PJM & MISO load and generation mix forecast (GWh)


PJM

Load 1942 17 1 1903 1928 1939 1916 1712

Generation

Coal 746 21 -11 717 732 720 707 689

Gas 411 17 34 424 411 393 379 336

Nuclear 701 -3 1 702 703 706 712 718

MISO

Load 1700 14 0 1669 1729 1775 1734 1575

Generation

Coal 868 8 -12 853 864 864 797 755

Gas 309 21 49 307 288 276 240 216

Nuclear 209 3 27 122 127 146 180 213

Source: Bentek

PJM & MISO spot natural gas prices ($/MMBtu)

Source: Platts

0.5

1.0

1.5

2.0

2.5

3.0

3.5


Chicago city-gates Columbia Gas App Tx.Eastern, M-3

PJM & MISO nuclear generation outages (GW)

Source: NRC

0

2000

4000

6000

8000

10000


2015 2014 2013

PJM & MISO MARKETS

PJM West weakens in mid-$30s/MWhMid-Atlantic day-ahead power prices tracked spot gas prices

lower Tuesday.

PJM West Hub day-ahead on-peak shed $1.50 to about $35/

MWh for Wednesday delivery on the IntercontinentalExchange.

PJM day-ahead off-peak sank $2.25 to below $22.50/MWh.

The PJM Interconnection forecast peakload to rise from around

89,475 MW Tuesday to near 90,850 MW Wednesday and 91,175

MW Thursday.

Texas Eastern M-3 day-ahead natural gas fell 19.4 cents to

$1.102/MMBtu.

Temperatures in the PJM Interconnection eastern region were

forecast more than 5 degrees above average with highs expected

in upper 60s to lower 80s.

Midcontinent dailies were flat to lower, ignoring higher

demand projections.

Indiana Hub day-ahead on-peak was steady to the previous

day at $32.75/MWh for Wednesday delivery, while day-ahead off-

peak fell 75 cents to $22.25/MWh.

The Midcontinent ISO predicted demand to peak near 82,050

MW Tuesday, 82,600 MW Wednesday and 84,150 MW Thursday.

Indianapolis temperature highs were forecast in the mid-70s

Tuesday and Wednesday, more than 5 degrees over the norm.

Dailies in the Midwestern portion of PJM mostly fell amid

weakness in nearby markets.

AD Hub day-ahead on-peak prices for Wednesday delivery

shed $1.25 to about $33.50/MWh, while day-ahead off-peak

dropped $2 to below $22.75/MWh. NI Hub day-ahead on-peak

bucked the regional trend, adding $2 to around $34/MWh.Mid-Atlantic forwards were flat to lower Tuesday afternoon

amid weaker regional gas basis.

PJM West Hub on-peak November was flat at roughly $38.25/

MWh on the IntercontinentalExchange around 2:30 pm EDT. The

PJM November package has fallen about $1.25 in the last month

and is $9.50 below the average November contract price seen in

October 2014. PJM on-peak December was also unchanged at

about $41.25/MWh, while the PJM on-peak January-February

contract shed 25 cents to around $53.50/MWh.

NYMEX November gas futures jumped 2 cents to $2.470/

MMBtu, while Texas Eastern M-3 November gas basis eased 2.1

cents to negative 79.6 cents/MMBtu.

Midwest forwards were flat to lower, mirroring movements innearby markets.

AD Hub and NI Hub on-peak November financial futures lost

25 cents each to around $35.50/MWh and $32.50/MWh,

respectively. Indiana Hub on-peak November was about $32.75/

MWh, steady to the previous day.

In the Southwest Power Pool, SPP North Hub November

on-peak gained about 25 cents to $22/MWh and SPP South Hub

November on-peak was steady around $27.50/MWh.

Market coverage

Platts provides a detailed methodology related to its coverageof North American electricity markets at:

http://platts.com/MethodologyAndSpecifications/ElectricPower.Questions can be directed to Eric Wieser at (202) 383-2092or [email protected].


9/20



MISO average day-ahead LMP for Oct 7 ($/MWh)

Avg Marginal


On-peak

Indiana Hub 30.01 -2.26 0.41 -2.96 28.97 17686

Michigan Hub 31.89 -0.92 0.95 -1.68 29.36 12328

Minnesota Hub 24.06 -6.83 -0.97 -7.30 24.00 9764

Illinois Hub 35.41 4.01 -0.46 0.77 30.14 14483

Off-Peak

Indiana Hub 20.71 0.38 0.51 -1.76 19.19 12033

Michigan Hub 22.50 2.10 0.59 0.28 19.77 8852

Minnesota Hub 13.63 -4.84 -1.34 -5.72 11.73 5578

Illinois Hub 22.80 3.18 -0.20 2.14 18.92 9461

PJM average day-ahead LMP for Oct 7 ($/MWh)

Avg Marginal


On-peak

AEP Gen Hub 30.37 -0.52 -1.19 -3.11 28.50 15288

AEP-Dayton Hub 31.49 -0.13 -0.46 -3.36 29.86 15850

ATSI Gen Hub 32.00 -0.26 0.19 -2.93 30.58 16521

Chicago Gen Hub 29.53 -0.52 -2.03 -2.18 26.52 12416Chicago Hub 33.07 2.52 -1.53 -1.08 27.81 13905

Dominion Hub 33.51 1.35 0.08 -2.95 32.10 14550

Eastern Hub 33.09 -0.21 1.22 -3.31 34.02 18820

New Jersey Hub 28.31 -4.01 0.24 -2.82 26.95 16103

Northern Illinois Hub 33.70 3.38 -1.77 -0.88 27.92 14167

Ohio Hub 31.27 -0.32 -0.48 -3.39 29.51 13217

West Internal Hub 32.32 0.41 -0.17 -2.95 31.06 22480

Western Hub 33.70 0.99 0.63 -2.45 32.25 23443

AEP Zone 31.93 0.14 -0.29 -3.28 30.47 16071

Allegheny Power Zone 33.01 0.53 0.40 -2.67 31.57 17688

Atlantic Elec Zone 27.86 -4.31 0.08 -2.95 26.83 15845

ATSI Zone 32.47 -0.22 0.61 -2.87 30.99 16763

BG&E Zone 44.86 11.45 1.33 3.77 38.63 23914

ComEd Zone 33.01 2.55 -1.62 -1.42 27.86 13881

Dayton P&L Zone 32.12 -0.41 0.44 -3.56 30.24 14191

Delmarva P&L Zone 33.54 0.29 1.17 -3.00 33.61 19079Dominion Zone 34.08 1.61 0.39 -2.91 32.68 14795

Duke Zone 30.72 -0.26 -1.09 -3.66 29.07 13576

Duquesne Light Zone 31.75 -0.16 -0.17 -2.66 30.80 19603

EKPC Zone 30.52 -0.26 -1.30 -3.41 28.87 18016

JCPL Zone 28.28 -4.09 0.29 -2.89 26.87 16085

MetEd Zone 29.41 -3.18 0.51 -4.73 27.23 15407

PECO Zone 28.04 -4.02 -0.02 -2.53 26.31 14686

Pennsylvania Elec Zone 31.19 -1.75 0.86 -2.83 29.65 19668

PEPCO Zone 37.28 4.28 0.91 -1.65 35.53 19874

PPL Zone 28.11 -4.13 0.16 -2.77 26.68 14724

PSEG Zone 28.54 -3.82 0.27 -2.71 27.08 16232

Rockland Elec Zone 28.41 -3.91 0.24 -2.95 27.03 16162

Off-Peak

AEP Gen Hub 22.53 -0.02 -0.43 -0.84 19.98 11311

AEP-Dayton Hub 22.99 0.04 -0.03 -0.95 20.53 11544

ATSI Gen Hub 22.96 -0.10 0.09 -0.86 20.68 11804Chicago Gen Hub 20.44 -1.53 -1.01 -0.42 17.44 8683

Chicago Hub 23.32 1.05 -0.70 0.18 18.45 9906

Dominion Hub 23.45 0.43 0.04 -0.94 21.19 10292

Eastern Hub 22.38 -0.73 0.13 0.60 23.28 12549

New Jersey Hub 21.30 -1.56 -0.11 -0.25 19.15 11944

Northern Illinois Hub 24.10 1.97 -0.84 0.37 18.61 10237

Ohio Hub 22.97 0.04 -0.05 -0.96 20.43 9849

West Internal Hub 23.03 0.12 -0.06 -0.86 20.78 15422

Western Hub 23.49 0.26 0.26 -0.55 20.96 15730

AEP Zone 23.08 0.05 0.05 -0.94 20.70 11588

Allegheny Power Zone 23.34 0.11 0.26 -0.63 20.95 12412

Atlantic Elec Zone 21.04 -1.77 -0.17 -0.29 19.09 11797

ATSI Zone 23.21 -0.11 0.35 -0.81 20.88 11929

BG&E Zone 26.88 3.22 0.69 0.38 23.25 14411

ComEd Zone 23.25 1.04 -0.76 -0.21 18.48 9875

Dayton P&L Zone 23.46 -0.01 0.49 -1.00 20.85 10486Delmarva P&L Zone 22.65 -0.48 0.15 0.91 23.02 12702

Dominion Zone 23.68 0.52 0.19 -0.95 21.40 10395

Duke Zone 22.67 0.02 -0.33 -1.05 20.21 10133

Duquesne Light Zone 22.86 -0.14 0.02 -0.79 20.70 13798

EKPC Zone 22.45 -0.03 -0.50 -0.96 19.98 13008

JCPL Zone 21.26 -1.59 -0.13 -0.30 19.09 11919

MetEd Zone 21.77 -1.04 -0.16 0.30 19.11 11349

PECO Zone 21.84 -0.90 -0.23 0.54 19.09 11383

Pennsylvania Elec Zone 22.83 -0.62 0.48 -0.42 20.30 14553

PEPCO Zone 24.64 1.26 0.41 -0.78 22.12 13209

PPL Zone 21.34 -1.42 -0.21 -0.05 19.05 11125

PSEG Zone 21.40 -1.51 -0.07 -0.23 19.23 11998

Rockland Elec Zone 21.44 -1.47 -0.06 -0.27 19.19 12023



PJM & MISO

Beaver Vly-2/FirstEnergy 943 n Penn. RF Unk 09/26/15

Braidwood-2/Exelon 1197 n Ill. MO Unk 10/04/15

Palisades/NMC 810 n Mich. MO Unk 09/15/15

Peach Bottom-3/Exelon 1182 n Penn. PMO Unk 09/21/15

Point Beach-2/NMC 559 n Wis. MO Unk 10/02/15

PJM & MISO Platts M2MS Forward Curve, Oct 6 ($/MWh)


PJM West 38.25 28.80

AD Hub 35.75 27.60

NI Hub 32.60 23.05Indiana Hub 32.65 25.50

NI Hub: Forward curve on-peak ($/MWh)

0

10

20

30

40

50

C a l - 1

9

C a l - 1

8

C a l - 1

7

C a l - 1

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Q 4 - 1 7

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A u g - 1 7

M a r

/ A p r

- 1 7

J a n / F e

b - 1 7

S e p - 1 7

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M a y

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NI Hub: Marginal heat rate on-peak (Btu/kWh)

10000

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Month 1

Month 2


10/20



ISONE average real-time LMP for Oct 5 ($/MWh)

Avg Marginal DA/RT Avg Mo

Hub/Zone Average Change $/Mo heat rate spread DA/RT

On-peak

Internal Hub 44.48 2.27 32.39 31630 -5.62 -3.56

Connecticut 43.91 2.74 32.02 26214 -5.46 -3.38

NE Mass-Boston 45.09 2.25 32.85 32059 -5.95 -3.71

SE Mass 44.35 1.99 32.42 31533 -5.76 -3.58West-Central Mass 44.53 2.44 32.40 31662 -5.61 -3.54

Rhode Island 44.25 1.73 32.38 31465 -5.79 -3.31

Maine 44.54 2.29 32.12 19708 -6.73 -3.76

New Hampshire 45.19 2.62 32.55 19994 -6.21 -3.61

Vermont 44.27 3.02 31.61 19590 -5.76 -3.20

Off-Peak

Internal Hub 26.33 5.63 17.24 18725 -2.99 1.12

Connecticut 26.01 5.45 17.14 15527 -2.92 1.16

NE Mass-Boston 26.54 5.77 17.34 18874 -3.06 1.12

SE Mass 26.41 5.71 17.27 18777 -3.01 1.10

West-Central Mass 26.34 5.65 17.25 18732 -2.98 1.14

Rhode Island 26.29 5.48 17.29 18695 -3.11 1.05

Maine 26.07 5.95 16.89 11536 -3.25 1.08

New Hampshire 26.39 5.97 17.09 11677 -3.08 1.19

Vermont 25.90 5.83 16.72 11458 -2.88 1.28

NYISO average real-time LMP for Oct 5 ($/MWh)



On-peak

Capital Zone 36.68 12.96 26.45 21512 -6.70 -1.34

Central Zone 36.99 14.05 25.70 27402 -7.88 -1.44

Dunwoodie Zone 37.10 13.04 26.90 20555 -6.34 -0.81

Genesee Zone 34.47 11.66 25.09 25532 -5.76 -1.25

Hudson Valley Zone 37.25 13.33 26.90 20638 -6.49 -0.90

Long Island Zone 67.10 42.48 33.27 37177 -34.08 -2.47

Millwood Zone 37.14 13.19 26.91 20576 -6.38 -0.84

Mohawk Valley Zone 35.36 12.66 25.55 22903 -6.53 -1.58N.Y.C. Zone 37.01 12.99 27.20 20503 -6.00 0.18

North Zone 29.04 9.93 21.84 12850 -5.71 -3.06

West Zone 58.03 35.08 29.80 42983 -28.92 -5.58

Off-Peak

Capital Zone 27.78 6.54 19.62 16295 -10.06 -4.08

Central Zone 26.74 6.41 17.28 19806 -9.52 -2.80

Dunwoodie Zone 28.83 7.22 19.59 15975 -10.65 -3.67

Genesee Zone 27.34 7.09 17.28 20254 -10.25 -2.99

Hudson Valley Zone 29.16 7.59 19.55 16154 -11.00 -3.69

Long Island Zone 28.88 -2.79 21.70 16001 -10.30 -3.39

Millwood Zone 29.00 7.31 19.61 16066 -10.83 -3.72

Mohawk Valley Zone 27.32 7.07 17.48 17696 -10.37 -3.07

N.Y.C. Zone 29.02 7.24 19.69 16076 -10.74 -3.58

North Zone 22.98 6.44 14.33 10169 -9.65 -2.78

West Zone 27.76 7.27 17.53 20561 -10.27 -3.00

Ontario average hourly prices for Oct 5 ($/MWh)

Avg Marginal


On-peak

IESO 32.75 2.12 41.11 13561

Off-Peak

IESO 25.98 -0.37 17.92 10758

PJM average real-time LMP for Oct 5 ($/MWh)



On-peak

AEP Gen Hub 31.00 6.79 25.42 16751 4.58 1.71

AEP-Dayton Hub 31.91 7.23 26.13 17239 3.70 2.41

ATSI Gen Hub 31.81 7.20 26.26 17597 3.42 3.16

Chicago Gen Hub 30.52 7.46 22.05 13475 -0.90 2.83Chicago Hub 35.50 10.19 24.25 15673 -4.91 1.24

Dominion Hub 33.74 7.83 27.27 15308 4.14 3.68

Eastern Hub 25.30 4.34 29.41 18983 5.10 4.32

New Jersy Hub 25.49 4.70 22.36 19128 4.04 3.48

Northern Illinois Hub 37.14 11.13 24.74 16395 -6.23 0.70

Ohio Hub 31.98 7.28 26.15 14098 3.38 1.98

West Internal Hub 32.34 7.37 26.49 25197 3.77 3.48

Western Hub 32.80 7.60 26.72 25560 3.93 4.46

AEP Zone 32.07 7.27 26.27 17329 3.94 2.96

Allegheny Power Zone 32.25 7.29 26.46 18488 3.89 4.00

Atlantic Elec Zone 25.12 4.41 22.30 18848 4.06 3.53

ATSI Zone 32.09 7.32 26.49 17752 3.47 3.34

BG&E Zone 40.07 10.17 31.35 25701 4.05 5.55

ComEd Zone 36.31 10.89 24.43 16031 -5.42 1.09

Dayton P&L Zone 32.68 7.24 26.77 15010 3.52 2.01

Delmarva P&L Zone 24.96 4.15 28.54 18731 5.30 4.49Dominion Zone 34.37 8.10 27.69 15595 4.14 3.85

Duke Zone 30.99 6.75 25.45 14230 4.12 2.23

Duquesne Light Zone 31.12 6.70 25.95 20935 4.24 3.94

EKPC Zone 30.74 6.67 25.18 19818 3.97 2.34

JCPL Zone 25.56 4.79 22.36 19184 3.99 3.37

MetEd Zone 25.40 4.73 22.28 15891 3.73 3.14

PECO Zone 25.01 4.52 21.99 15650 3.92 3.12

Pennsylvania Elec Zone 29.81 6.40 24.97 20157 3.59 3.49

PEPCO Zone 36.98 9.37 29.26 23720 4.03 5.24

PPL Zone 25.51 4.76 22.33 15961 3.87 3.23

PSEG Zone 25.56 4.74 22.39 19180 4.10 3.56

Rockland Elec Zone 26.15 4.96 22.74 19624 3.66 3.14

Off-Peak

AEP Gen Hub 36.68 20.92 19.87 19819 -12.98 -1.08

AEP-Dayton Hub 37.45 21.44 20.25 20233 -13.28 -0.90

ATSI Gen Hub 37.13 21.06 20.34 20545 -13.34 -0.75Chicago Gen Hub 35.76 20.51 18.41 15789 -15.26 -2.26

Chicago Hub 39.41 23.01 20.27 17401 -18.25 -3.73

Dominion Hub 39.31 23.34 20.57 17836 -14.24 -0.46

Eastern Hub 29.74 14.02 19.45 22322 -8.64 4.31

New Jersy Hub 29.82 14.34 18.44 22380 -8.71 -0.19

Northern Illinois Hub 40.60 23.86 20.64 17926 -19.37 -4.15

Ohio Hub 37.51 21.48 20.28 16535 -13.40 -1.06

West Internal Hub 37.78 21.83 20.33 29442 -13.63 -0.62

Western Hub 37.93 22.05 20.36 29556 -13.85 -0.52

AEP Zone 37.61 21.55 20.32 20323 -13.34 -0.76

Allegheny Power Zone 37.72 21.74 20.37 21626 -13.61 -0.50

Atlantic Elec Zone 29.56 14.03 18.47 22183 -8.69 -0.22

ATSI Zone 37.32 21.16 20.47 20648 -13.36 -0.69

BG&E Zone 45.71 29.51 22.17 29314 -18.26 -0.31

ComEd Zone 39.68 23.24 20.28 17517 -18.38 -3.75

Dayton P&L Zone 38.33 21.90 20.69 17604 -13.73 -1.08Delmarva P&L Zone 29.52 13.79 19.37 22156 -8.46 3.98

Dominion Zone 39.90 23.87 20.76 18104 -14.64 -0.46

Duke Zone 36.75 20.94 19.85 16878 -12.72 -0.83

Duquesne Light Zone 36.48 20.51 20.15 24545 -12.75 -0.47

EKPC Zone 36.59 20.89 19.65 23587 -12.88 -0.84

JCPL Zone 29.89 14.44 18.42 22434 -8.84 -0.25

MetEd Zone 29.59 14.02 18.47 18514 -8.78 -0.37

PECO Zone 29.39 13.88 18.37 18388 -8.57 -0.27

Pennsylvania Elec Zone 34.45 18.41 19.82 23299 -11.62 -0.62

PEPCO Zone 42.50 26.42 21.40 27256 -16.41 -0.44

PPL Zone 29.82 14.31 18.46 18658 -8.87 -0.34

PSEG Zone 29.84 14.36 18.44 22396 -8.60 -0.12

Rockland Elec Zone 30.46 14.92 18.59 22861 -9.22 -0.35


11/20



Alberta average hourly prices for Oct 5 ($/MWh)

Avg Marginal


On-peak

AESO 24.78 3.83 37.62 9921

Off-Peak

AESO 18.48 -1.95 17.17 7399

CAISO average real-time LMP for Oct 5 ($/MWh) Avg Marginal DA/RT Avg Mo


On-peak

NP15 Gen Hub 96.94 56.77 45.66 34346 -60.67 -12.90

SP15 Gen Hub 95.80 56.13 44.80 41560 -60.87 -12.20

ZP26 Gen Hub 95.09 55.26 44.50 41254 -59.97 -12.52

Off-Peak

NP15 Gen Hub 24.76 0.17 26.53 8772 2.67 0.98

SP15 Gen Hub 24.47 0.26 25.78 10615 2.87 1.54

ZP26 Gen Hub 24.54 0.21 25.79 10648 2.77 1.29

ERCOT average real-time LMP for Oct 5 ($/MWh)



On-peak

Bus Average 20.08 -2.12 20.41 9035 5.13 3.03

Hub Average 20.08 -2.12 20.48 9035 5.30 3.18

Houston Hub 20.07 -2.13 20.77 8732 6.17 3.83

North Hub 20.08 -2.12 20.26 9035 4.90 2.78South Hub 20.07 -2.13 20.57 8936 5.09 3.14

West Hub 20.09 -2.11 20.31 9468 5.07 2.97

AEN Zone 20.08 -2.12 20.45 9465 5.35 3.28

CPS Zone 20.09 -2.11 20.61 8943 5.95 4.33

LCRA Zone 20.08 -2.12 20.53 8939 5.38 3.27

Rayburn Zone 20.08 -2.12 20.26 9035 4.86 2.76

Houston Zone 20.07 -2.13 20.89 8732 6.77 4.20

North Zone 20.08 -2.12 20.26 9035 5.40 3.09

South Zone 20.17 -2.03 20.67 8978 7.64 4.53

West Zone 20.09 -2.11 20.32 9469 6.78 4.04

Off-Peak

Bus Average 18.03 0.68 17.03 8114 -0.59 -0.80

Hub Average 18.03 0.68 17.05 8114 -0.58 -0.81

Houston Hub 18.03 0.68 17.15 7843 -0.54 -0.85

North Hub 18.03 0.68 16.98 8112 -0.61 -0.79

South Hub 18.03 0.68 17.08 8027 -0.58 -0.79West Hub 18.03 0.68 16.99 8500 -0.60 -0.79

AEN Zone 18.03 0.68 17.00 8500 -0.59 -0.82

CPS Zone 18.03 0.68 17.14 8027 -0.53 -0.65

LCRA Zone 18.03 0.68 17.03 8027 -0.59 -0.82

Rayburn Zone 18.03 0.68 16.98 8112 -0.61 -0.79

Houston Zone 18.03 0.68 17.15 7843 -0.53 -0.84

North Zone 18.03 0.68 16.98 8112 -0.61 -0.79

South Zone 18.03 0.68 17.12 8027 -0.53 -0.75

West Zone 18.03 0.68 17.00 8500 -0.60 -0.79

MISO average real-time LMP for Oct 5 ($/MWh)



On-peak

Indiana Hub 34.98 10.56 26.94 22547 -3.19 1.01

Michigan Hub 37.94 12.26 27.99 15383 -5.89 0.02

Minnesota Hub 29.02 8.59 21.04 12693 0.15 1.48

Illinois Hub 43.09 19.59 26.53 18879 -11.25 1.66Off-Peak

Indiana Hub 21.51 0.55 18.87 13865 -0.12 -0.64

Michigan Hub 23.46 1.36 19.47 9511 -2.16 -0.74

Minnesota Hub 16.93 1.99 8.42 7405 -0.92 1.40

Illinois Hub 21.65 1.60 18.54 9484 -1.45 -0.75

MISO South average real-time LMP for Oct 5 ($/MWh)



On-peak

Arkansas Hub 29.43 7.00 23.78 13609 -0.97 1.93

Louisiana Hub 29.78 7.14 24.22 13592 -0.08 2.78

Texas Hub 29.19 6.74 24.15 12696 -0.44 3.71

Off-Peak

Arkansas Hub 20.69 1.16 18.75 9569 -1.29 -0.14

Louisiana Hub 20.78 0.96 18.98 9481 -0.49 0.07

Texas Hub 20.71 0.93 19.10 9009 -0.45 0.16

SPP average real-time LMP for Oct 5 ($/MWh)



On-peak

SPP North Hub 20.02 0.39 18.66 8792 1.52 -0.31

SPP South Hub 22.47 0.62 21.33 10590 3.86 2.94

Off-Peak

SPP North Hub 16.16 0.23 13.89 7097 -0.62 -0.16

SPP South Hub 19.46 1.46 17.14 9170 0.11 1.40


12/20



NEWS

Wind, ‘dirt cheap’ gas stifle Central power pricesStronger demand in the central US in September failed to

boost power markets as weak natural gas prices continued to

suppress day-ahead electricity markets.

After a run of record-breaking demand in August, Texas power

prices cooled in September, even as peak loads were higher year

over year.

The Electric Reliability Council of Texas’ North Hub day-ahead

on-peak averaged $27.93/MWh in September, more than 52%

lower than August and about 26% below September of last year.

ERCOT Houston Hub day-ahead on-peak averaged $28/MWh

in September, almost 54% below August and more than 28%

below the same period in 2014.

ERCOT peak load in September averaged about 56,400 MW,

down 10% from August but up 5% compared with September of

last year, as regional temperatures averaged over 80 degrees

Fahrenheit, 1 degree above normal and 2 degrees above September

2014.

The Midcontinent Independent System Operator’s Texas Hub

also had lower day-ahead on-peak prices in September, averaging

$30.69/MWh, down more than 18% from August and 21% lower

than September 2014.

Spot natural gas prices and strong wind generation both

contributed to September’s decline relative to last year.

“Dirt cheap natural gas is certainly playing a factor,” said

Gurcan Gulen, senior energy economist at the University of Texas

Bureau of Economic Geology, on Tuesday. “We still have some

excess wind that might be causing prices to be lower.”

For spot gas prices, Houston Ship Channel averaged $2.61/MMBtu in September, around 34% lower than the same period

last year.

During September, peak wind generation averaged over 7,000

MW, a 56% increase over September 2014.

Further, ERCOT had a new record for peak wind generation on

September 13 of 11,467 MW, which was at the time serving close

to 30% of the load.

Cheap wind generation eroded regional spark spreads despite

falling fuel costs for gas-fired generators. September spark spreads

at ERCOT North Hub averaged about $8.65/MWh, less than half

the average August spark spread even when excluding scarcity

pricing days.

ERCOT, MISO Texas forwards differERCOT forward months day-ahead prices are generally at a

discount to September, while the MISO Texas Hub’s forward curve

slopes upward—likely because of expectations of congestion in

that region.

On September 29, ERCOT Houston’s October on-peak package

had a 5% premium to the September day-ahead on-peak average,

but the November package had a 4.3% discount, and the

December package had a 7% discount.

The ERCOT North packages of all three of the remaining

months of 2015 had a discount compared with September’s day-

ahead on-peak average price. The October discount was about 2%

the November discount was about 7%, and the December

discount was about 5%.

At the same time, MISO’s Texas Hub October package

premium was more than 14% over the September day-ahead

on-peak average, November’s premium was more than 15%, and

December’s premium was more than 18%.

Speculating about the difference in forward prices for MISO

Texas, versus ERCOT, UT’s Gulen said, “It could be a congestion

issue.”

“They’re pretty similar in terms of climate,” Gulen said. “They

have a lot of industrial load concentrated [in MISO Texas], which

… could be contributing to congestion.”

Up north in the Midwest, higher-than-normal demand kept

power prices firm in the face of falling natural gas prices.

MISO’s Indiana Hub day-ahead on-peak averaged $32.09/MWh

up 2.5% from August but down 12.5% from September 2014.Peak load in the MISO averaged just over 93,000 MW, down

7% from August but up 6% from September 2014, as temperatures

averaged 3 degrees higher than normal at 69 degrees.

Gas prices at Chicago city-gates, which are most relevant for

Indiana Hub, had a slight month-to-month decline, averaging

$1.94/MMBtu for September, down 9 cents from August. Spark

spread responded by increasing almost $3 to $18.43/MWh.

Total wind generation in MISO registered at 2,945 GWh for

Day-ahead average on-peak prices ($/MWh)

% change % changeLocation September 2015 August 2015 August-September September 2014 Year to year October 2015* November 2015*

PJM Northern Illinois Hub 32.43 31.96 1.48% 35.00 -7.4% 32.85 33.30

SPP North Hub 22.28 27.36 -18.57% 27.19 -18.0% 22.85 23.55

SPP South Hub 29.26 31.38 -6.76% 39.77 -26.4% 27.70 28.20MISO Indiana Hub 32.09 31.31 2.50% 36.68 -12.5% 33.35 33.40

MISO Texas Hub 30.69 37.59 -18.37% 39.02 -21.4% 35.10 35.35ERCOT Houston Hub 28.00 60.78 -53.93% 39.09 -28.4% 29.45 26.80

ERCOT North Hub 27.93 58.62 -52.36% 37.63 -25.8% 27.45 26.00

ERCOT West Hub 27.94 58.97 -52.63% 37.68 -25.9% 26.70 25.25

*As of September 29.

Source: Platts price database.


13/20



September, up 533 GWh from August and 623 GWh from 2014.

The excess wind generation offset cheaper fuel costs to drive spark

spreads down to only $10.10/MWh, $6 below August levels.

Indiana Hub Q4 prices higherAs of September 29, the Indiana Hub October and November

packages had premiums of about 4% over the September day-

ahead on-peak average, and the December package’s premium was

about 5%.

September’s average day-ahead on-peak price for the PJM

Interconnection’s Northern Illinois Hub, which includes the

Chicago area, increased 1.5% from the August average, but the

September price was down by more than 7% from September

2014.

The NI Hub October on-peak package as of September 29 had

a 1.3% premium over the September day-ahead on-peak average.

November’s premium was almost 3%, and December’s premium

was almost 4%.

In the Southwest Power Pool, SPP North Hub took a drubbing

month over month and year over year, while SPP South Hub’s

decline was moderated month to month, but the year-over-year

drop was striking. Declines can be attributed to lower gas prices

and higher wind generation.

SPP North Hub day-ahead on-peak averaged $22.28/MWh in

September, down close to 19% from August and 18% from same

period in 2014.

SPP South Hub day-ahead on-peak averaged $29.26/MWh last

month, down 7% from August, but 26% lower than September

2014.

Natural gas prices in the SPP region averaged about $2.66/

MMBtu in September, down 12 cents from August and down

$1.24 from 2014. Additionally, wind generation accounted for

almost 14% of market share in September, up from 9% in August,driving regional spark spreads down to just $1.54/MWh, Bentek

Energy data showed.

Judging by forward packages for the remainder of the year,

traders expected prices in SPP North Hub prices to be higher and

SPP South Hub prices to be lower.

As of September 29, SPP North Hub on-peak October had a

2.5% premium over September’s average day-ahead on-peak price.

The November premium was almost 6%, and the December

premium was almost 7%.

At the same time, SPP South Hub on-peak October had a

discount of more than 5% from the September average day-ahead

on-peak price. The November discount was almost 4%, and the

December discount was more than 10%. — George McGuirk, Mark Watson and Eric Wieser

Michigan PSC study touts energy efficiencyWhile neighboring Ohio freezes its energy efficiency standards,

Michigan’s energy waste reduction efforts are saving customers

billions of dollars over the life of the programs, according to a

new study.

“The report is indicating it is cost- effective,” Judy Palnau,

spokeswoman for the Michigan Public Service Commission, said

Tuesday about her agency’s newly released report on energy

efficiency, referred to in Michigan as “energy optimization.”

Since the programs started in 2009, shortly after former

Democrat Governor Jennifer Granholm signed into law PA 295, a

comprehensive energy bill, they have saved customers money

every year, the report found. Overall program expenditures of $1.

billion from 2010 to 2014 are estimated to achieve lifetime

savings to all customers of $4.2 billion, nearly a four-fold returnon investment.

“The cheapest energy is the energy never used, and this has

proven to be the case again with Michigan’s energy optimization

programs in 2014,” PSC chairman John Quackenbush said.

“Because they focus on reducing energy waste, energy efficiency

programs benefit all utility customers.”

For every dollar that was spent on programs to save energy in

2014, customers can expect to realize $4.38 in savings, more than

any year since 2010, he said.

“Customers who take advantage of energy efficiency programs

personally benefit even more,” Quackenbush added.

Program expected to save $1.12 billionCurrently, the state’s energy savings targets are 1% of total

retail sales for electric providers and 0.75% of total retail sales for

gas providers on an annual basis. Last year, the programs

accounted for more than 1.4 million MWh in electric savings and

4.86 Bcf in gas savings.

In 2014 alone, aggregate energy efficiency program spending

of $257 million by all electric and natural gas utilities in Michigan

were expected to result in lifetime savings to customers of $1.12

billion, the report said.

RGGI carbon allowance futures, Oct 5 ($/allowance)

ICE Settlement Volume

Dec15 V14 6.70 0

Dec16 V14 6.91 0

Dec17 V14 7.12 0

Dec18 V14 7.33 0

Dec15 V15 6.70 0

Dec16 V15 6.91 0

Dec17 V15 7.12 0

Dec18 V15 7.33 0

Dec15 V16 6.70 0

Dec16 V16 6.91 0

Dec17 V16 7.12 0

Dec18 V16 7.33 0

The Regional Greenhouse Gas Initiative is a carbon cap-and-trade program for power generatorsin nine Northeast and Mid-Atlantic US states. One RGGI allowance is equivalent to one shortton of CO2. The volume listed is the number of futures contracts traded. Each futures contractrepresents 1,000 RGGI allowances.

Daily CSAPR allowance assessments, Oct 6 ($/st)

$/st 2015 Range $/st 2016 Range

Nox Annual 125.00 100.00-150.00 120.00 95.00-145.00

NOx Seasonal 237.50 200.00-275.00 232.50 195.00-270.00

SO2 Group 1 4.50 1.00-8.00 2.25 0.50-4.00

SO2 Group 2 22.50 5.00-40.00 18.75 2.50-35.00

mailto:[email protected]:[email protected]


14/20



In fact, the programs are doing so well in Michigan, and are so

popular with customers, some legislators and utilities say it may

be time to strip away the mandate and offer energy efficiency on a

voluntary basis.

“The report underscores what we know, which is reducing

energy waste is a very popular concept with customers,”

Consumers Energy spokesman Dan Bishop said Tuesday.

“Customers like the specific, practical tips that help them lower

their energy bills and save money.”

Consumers, a CMS Energy subsidiary with 1.8 million

customers, is the state’s second-largest electric utility, trailing DTE

Energy and its 2.1 million customers.

However, whether energy efficiency stays or goes as a mandate

“will be up to the policymakers as they finalize deliberations” on a

new comprehensive energy bill taking shape in the Legislature,

Bishop said. Preliminary votes could come before the end of

October in the Michigan House of Representatives, controlled by

Republicans as is the state Senate. Governor Rick Snyder also is a

member of the GOP.

Attracting the most attention so far among legislators is aproposal to either eliminate Michigan’s retail open access law or

keep a hard, 10% cap on choice.

Some consumer advocates, including the Union of Concerned

Scientists, are urging lawmakers to keep the energy efficiency

mandate intact.

Snyder, re-elected to a second, four-year term last November,

has not said if he backs the mandate. But he is clearly an

outspoken advocate of what he calls energy “waste reduction.”

In a long-awaited energy speech in mid-March, Snyder said

Michigan must meet 30-40% of its energy needs by 2025 with

energy efficiency and renewables, with natural gas also playing a

key role in replacing the state’s heavy reliance on coal-fired

generation. — Bob Mat yi

NV Energy lowers rates as wholesale prices fallNV Energy, the regulated utility in Nevada owned by Warren

Buffet’s firm Berkshire Hathaway Energy, has lowered its

residential, commercial and industrial customer rates amid

historically low wholesale power prices.

On October 1 the Las Vegas-based utility announced that retail

rates in southern Nevada were to decrease 2.19%, while northern

Nevada residential, commercial and industrial electric customers

would see “an overall electric rate decrease of 4%.”

The company, which claimed in a recent earnings report that

it had “higher regulated electric operating revenue” in the second

quarter and first half of 2015, said last week that its rate

reductions were due “to the company’s management of costs

associated with fuel and purchased power used to provide

electricity.” It said, “These costs are passed through directly to ou

customers, dollar for dollar, with no profit to the company.”

NV Energy said that a “typical” southern Nevada single-family

residential customer bill of $149.71, based on average usage of

1,141 kilowatt-hours a month, “will see a decrease of

approximately 1%, or $1.35.” It said that, when added to a 3.13%

decrease on July 1, “a typical southern Nevada single-family

residential customer monthly bill has been reduced $6.18 since

the beginning of the year.”

NV Energy provides power to 1.3 million customers

throughout Nevada, plus nearly 40 million tourists annually.

There has been brewing discontent with NV Energy prices,

however. In May, three casinos—MGM Resorts, Wynn Resorts and

Las Vegas Sands—filed applications with the Public Utilities

Commission of Nevada seeking approval to buy “energy, capacity

and/or ancillary services from a provider of new electric

resources.”

The casinos’ assertions have been that they could buy power

directly from new solar or wind installations at a cheaper price

than they have been paying NV Energy. The PUCN has not yet

ruled on the applications, but has indicated it could rule on it

before the end of the year. In the meantime, NV Energy has said i

will not increase its electric base rates for southern Nevada “for

the next three years.”

Wholesale power prices at nearby Mead Hub are as low as theyhave been since June 2012. The average Mead day-ahead, on-peak

price in September was $31.33/MWh, and has fallen to $27.75/

MWh so far in October. This is against a $36.63/MWh monthly

average stretched out over four years.

The decline, though, in the Calendar Year 2016 Mead on-peak

forward price has been even more dramatic. In 2012, the average

June CY16 on-peak price was $49.23/MWh. It then declined

gradually to $41.95/MWh in January 2014. Seventeen months later

in July 2015, the average CY16 price was $33.35/MWh. Thus far in

October, the average CY16 forward price has been $28.83/MWh.

Electric energy optimization savings 2009-2014 (TWh) in Michigan

Source: Michigan Public Service Commission

0

1

2

3

4

5

6

7

8

6 Year Actual6 Year Target

4.7

6.1

Mead wholesale power prices ($/MWh)

Source: Platts

20

30

40

50

60

70

80

Oct-15Apr-15Oct-14Apr-14Oct-13Apr-13Oct-12Apr-12

Average of Mead day-ahead on-peak

Average of Mead on-peak CY16

mailto:[email protected]:[email protected]


15/20



NV Energy’s cost of purchased power could be pushed higher

by some of its agreements with renewable sources.

The state’s largest solar facility, the 110-MW Crescent Dune

concentrating solar thermal unit at Tonopah, Nevada, which has

been completed but not brought fully online, has a 25-year supply

contract with NV Energy. NV Energy will pay $135.00/MWh for

the power, and that price will increase 1% each year.

The company also is supplied power by 17 geothermal power

facilities located in the state with combined capacity of almost

400 MW.

According to data file with the Federal Energy Regulatory

Commission, Ormat Nevada, which operates many of the

geothermal units, was the third top seller of wholesale power into

the Mead Hub in the second quarter 2015. According to the data,

Ormat sold 210,781 MWh of geothermal power at an average

price of $8.67/MWh.

— Jeffrey Ryser

Oncor deal, ERCOT fee hike on PUC agendaThursday’s Public Utility Commission of Texas meeting will

focus on issues related to the sale of Texas’ largest transmission

system and a potential increase of the Electric Reliability Council

of Texas system administration fee.

The commission will consider a draft preliminary order laying

out 147 questions that should be addressed as the PUC considers

the September 29 joint application of Oncor Electric Delivery,

Ovation Acquisition I, Ovation Acquisition II and Shary Holdings

to restructure and transfer control of Oncor to Ovation I, Ovation

II and Shary Holdings, which are affiliates of Hunt Consolidated

(Docket No. 45188).

On August 9, the Ovation entities entered into a merger

agreement with Energy Future Holdings, which owns 80% ofOncor, the state’s largest transmission company, and is in Chapter

11 bankruptcy proceedings, and Energy Future Intermediate

Holding Company.

That deal calls for Ovation I to acquire EFH’s 80% stake in

Oncor, which would be reorganized into two companies. One of

these companies, Oncor AssetCo, would hold legal title to all

Oncor transmission and distribution assets. The other company,

Oncor OpCo, would operate the assets and hold Oncor’s

certificates of convenience and necessity and other personal

property. Shary Holdings, owned by Hunter Hunt and his family,

would have operational control of Oncor Opco. Ovation I would

indirectly own Oncor AssetCo and qualify to be taxed as a real

estate investment trust.The transaction is part of EFH’s fifth amended joint plan to

emerge from Chapter 11 bankruptcy, and must happen before the

joint plan can be completed.

Under state law, the PUC must rule on the application for

transfer of control by March 27, which is a Sunday. If the PUC

does not meet this deadline, the application is automatically

approved.

The commission plans to take final action on the issue at an

open meeting on March 24, the draft preliminary order states,

“although it is likely it will deliberate on this matter at an earlier

open meeting.”

“In any event, at this time, the Commission intends to issue

its order on this matter on Friday, March 25, 2016, although that

date could slip,” the draft preliminary order states.

Issues to be addressed include whether the transaction is in

the public interest, how the real estate investment trust structure

would affect ratepayers, whether the PUC would have to approve

any lease agreements between the AssetCo and Opco, and how

the bankrupt parent company’s debt burden might affect the

AssetCo and OpCo.

In other business, the PUC will consider ERCOT’s budget for

2016 and 2017 and whether to approve an increase in the system

administration fee from 45.6 cents/MWh to 55.5 cents/MWh

(Docket No. 38533).

ERCOT’s proposed budget is $219.9 million for 2016 and 223.

million for 2017. The 2015 budget called for spending almost

$195 million.

One reason to increase the fee increase is that load is expected

to grow more slowly than inflation, a memo filed Thursday by

PUC counsel Thomas Hunter states.

“While the Texas economy is still healthy and growing, the

decoupling of economic growth and load growth is a challenge

for ERCOT’s model of funding, which is based almost exclusively

on megawatt hours used by Texas consumers,” the memo states.

“ERCOT observes that while its revenues are sensitive to energy

consumption, the costs of meeting its statutory obligations

seldom are.”

— Mark Watso

EIA forecasts drop in winter heating expenditure

Expectations for winter temperatures to be above the 10-yearaverage across much of the US would drag natural gas

expenditures for the average household down 10% from last

winter’s costs, the Energy Information Administration said

Tuesday in its monthly outlook.

The agency’s October Short-Term Energy Outlook, which took

a hard look at projected winter fuel needs, forecast residential gas

demand to fall 6% this winter.

US electricity generation by fuel (GWh/d)

Note: Data for 2015 and 2016 are forecasts.

Source: EIA's Short-Term Energy Outlook

0

2000

4000

6000

8000

10000

12000

201620142012201020082006

Coal

Hydropower

Natural gas

Renewables

PetroleumNuclear

Other sources

mailto:[email protected]:[email protected]:[email protected]:[email protected]


16/20



Henry Hub natural gas spot prices are expected to be 13% below

last winter’s prices, EIA said, but residential prices for gas will only

see a 4% decline from last winter. EIA explained that “changes in

spot prices do not quickly translate into lower delivered residential

prices” as the rates utilities charge are often “set by state utility

commissions a year or more in advance and reflect the cost of gas

purchased over many months.” The agency added that residential

prices also “include a fixed component to cover utility operating

costs and the cost to transport the natural gas.”

Nearly half of all US households keep warm during the winter

with gas.

“Natural gas supplies should be adequate to meet demand this

winter, as average household natural gas consumption during the

heating season is expected to be the lowest in four years,” EIA

Administrator Adam Sieminski said in a statement Tuesday.

He added, “If winter temperatures come in as expected by US

government weather forecasters, US consumers will pay less to

stay warm this winter no matter what heating fuel they use.”

About 39% of US households rely on electricity as their

primary heating source. Those households are expected to spend

about $30, or 3%, less on heating costs this winter “as a result of

1% lower residential electricity prices and 2% lower consumption

than last winter,” EIA said.

However, these projections, EIA cautioned, are based on the

latest forecasts from the National Oceanic and Atmospheric

Administration, and “weather can be unpredictable.”

“Under a 10% colder scenario, EIA projects natural gas

consumption to be 1% higher than last year, but expenditures

would still be 4% lower than last year. Under a 10% warmer

scenario, EIA expects declines of 14% in consumption and 17% in

expenditures compared with last year,” the agency said.

For households that heat with electricity, a colder winter

would see a 1% rise in residential electricity demand, withexpenditures expected to be flat from last winter, EIA said.

“Residential electricity prices would not rise immediately, but the

effect of colder temperatures would pass through to retail

electricity rates over the succeeding months of 2016.”

The report highlighted that pipeline constraints continue to

pose a threat to gas-fired generation, so day-to-day price volatility

was still likely for the winter.

But an analyst speaking at a supply and demand forecast even

Tuesday said that he believed the market was “tremendously

overpricing … New England gas this winter out of fear, auto-

correlation and the ‘I don’t know’ factors” inherent to such

projections.

Charles Blanchard, lead natural gas analyst at Bloomberg New

Energy Finance, referred to spot gas prices at the Algonquin

Citygate hub as “a spiky market” that must be thought about in

terms of the frequency of price spikes and the level to which

prices will spike.

“We determined, given NOAA’s outlook on temperatures this

year, how many price spikes should there be, and it’s fewer than

last year,” he told attendees at the 2015 Winter Energy Outlook

Conference hosted by DOE’s Office of Electricity Delivery and

Energy Reliability, EIA and the National Association of State

Energy Officials.

Further, he said price spikes would be constrained to the cost

of generators’ fuel alternatives, which in New England are LNG

and oil. “Both of those are much cheaper than they were last

winter,” he said.

According to Blanchard, distillate fuel oil is currently priced at

about $11.50/MMBtu delivered to Boston, while residual oil is at

about $7.50/MMBtu. Spot LNG prices are closer to $7/MMBtu now

as well.

“So whereas last year you might have had the spike to $12,

$13, $15 for LNG, this year you don’t have to spike too much

above $7 to get hold of incremental gas or incremental negative

molecules of gas by oil switching,” Blanchard said.Fear and the natural auto-correlation phenomenon, where

individuals assume this winter will be bad because the last two

winters bad, were driving expectations for higher gas prices in

New England.

Blanchard added that the pipeline capacity issues that have

driven up New England gas prices in the past would probably be

Henry Hub natural gas price ($/MMBtu)

Note: Data for October 2015 and beyond are forecasts.


0

1

2

34

5

6

7

201620152014

Spot price Forecast price NYMEX futures price

95% NYMEX futures upper condence interval

95% NYMEX futures lower condence interval

US natural gas supply and demand

Note: Data for October 2015 and beyond are forecasts.


0

20

40

60

80

100

120

2016201520142013-4

-2

0

2

4

6

8(Bcf/d) (Year-over-year change, Bcf/d)

Total consumption (left axis)

Consumption forecast (left axis)Total production (left axis)

Production forecast (left axis)

Electric power demand (right axis)

Residential and commercial demand (right axis)Industrial demand (right axis)

Other demand (right axis)


17/20



solved by the addition of one or two new pipelines “in the pretty

near future.”

Sieminski noted that gas-fired electricity generation surpassed

generation from coal for July — the second time that has ever

happened. But “higher natural gas prices by February are expected

to keep the amount of natural gas-fired electric generation below

coal-fired generation levels at least through the winter months,”

Sieminski said.

EIA lowered its forecast for fourth-quarter Henry Hub natural

gas spot prices to $2.83/MMBtu, 12 cents below its estimate in

September. The agency expects monthly average spot prices “to

remain lower than $3/MMBtu through January, and lower than

$3.50/MMBtu” through the end of 2016, the report said.

The report added that Henry Hub natural gas prices are

projected to average $2.81/MMBtu in 2015 and $3.05/MMBtu in

2016.

Despite these relatively low gas prices, “increases in drilling

efficiency will continue to support growing natural gas

production,” EIA said.

The agency raised its natural gas marketed production estimate

for Q3 by 350 MMcf/d to 79.37 Bcf/d, while its Q4 estimate was

unchanged at 79.61 Bcf/d.

The report added that gas marketed production is expected to

grow at an annual rate of 5.6% in 2015 to 79.06 Bcf/d and at 1.9%

in 2016 to 80.58 Bcf/d.

Production continues to outpace demand through EIA’s

forecasted period.

The agency raised its Q3 demand estimate by 320 MMcf/d to

66.39 Bcf/d, while lowering its Q4 demand estimate by 1 Bcf/d to

77.99 Bcf/d.

EIA said that demand for US gas for the full year is expected to

average 76.20 Bcf/d — 320 MMcf/d below last month’s estimate —

compared with 73.15 Bcf/d in 2014.By sector, gas demand for power is projected to rise in 2015,

supported by gas prices below $3/MMBtu, but fall off in 2016 as

gas prices edge up, EIA said. “Industrial sector consumption

remains flat in 2015 and increases by 4.2% in 2016, as new

industrial projects, particularly in the fertilizer and chemicals

sectors, come online late this year and next year, and as industrial

consumers continue to experience low natural gas prices,” the

agency said.

Gas demand in the residential and commercial sectors is

forecast to decline in both 2015 and 2016, the report said.

— Jasmin Melv in

sustainability issues, the mayor said. Included in the settlement

was an agreement to pursue the purchase of additional of wind

generation, 100 MW in total, to power DC buildings, Bowser said.

The mayor’s office has asked the PSC to support the

settlement.

“In August, the Commission rejected the proposed merger as

filed and noted that ‘there was no settlement brought to the

commission that would have evidenced general agreement

DC, Exelon reach agreement merger...from page 1

satisfying concerns raised by the parties in this proceeding,” the

filing with the PSC made Tuesday said.

That decision spurred negotiations to reach a strong package

of commitments that would satisfy the commission’s public

interest standard, the filing said.

The DC consumer advocate, the Office of the People’s

Counsel, and others joined the settlement.

“The bottom line, this is a good deal,” Sandra Mattavosa-Frye,

the People’s Counsel, said.

The most important aspects are the checks and balances that

include ways to measure and verify Exelon’s commitments to

renewable generation, the people’s counsel said.

The settlement also addresses issues that slowed

interconnection of solar, for example, Mattavosa-Frye said.

Interconnection agreements will no longer take months and

the $100 fee will be eliminated, she said.

Exelon and the city have asked the PSC whether the

agreement must be filed as a new merger application or whether i

can be considered as part of the application that was rejected by

the PSC in August.

“The Joint Applicants believe that the Commission can and

should consider the Settlement Agreement as part of [the existing

case],” the filing said.

The company and the city believe the commission has the

authority to modify its prior decision.

Others disagree, however, “Any prospective settlement has

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Regional trends mixed for gas-fired generatorsGas-fired generators in the Northeast and Midwest have

benefited from firming power prices on account of unseasonably

high September demand, while generation margins were pressured

in the rest of the country by factors like higher than normal wind

generation or regionally elevated gas prices.

Temperatures in the Midwest and Northeast about 3-4 degrees

above normal sustained cooling demand and drove elevated

power usage. Average September peak load registered 5% higher

than 2014 in ISO-NE and MISO and 8% higher in NYISO.

Elevated demand in these regions propped up power prices in

the face of falling fuel costs, and gas-fired generators saw market

clearing spark spreads rise approximately $3-4/MWh.

While ERCOT and SPP also saw higher-than-normal peak load

and falling gas prices in September, high levels of wind generation

weighed on power prices driving spark spreads lower.

Average peak load in ERCOT was 5% higher this September

compared to last year, but total wind generation climbed almost5% from August and accounted for approximately 9.3% of the

fuel mix in September, up from 7.7% in August and 6.3% in

September 2014.

ERCOT reached a new record wind generation peak on

September 13 of 11,467 MW, which was at the time serving close

to 30% of the load.

As a result, spark spreads at ERCOT North Hub fell to $13.05/

MWh, less than half of August levels. Ignoring peak demand days

in August, which lead to scarcity pricing events in ERCOT,

September spark spreads were still down almost $9/MWh.

Spark spreads mixed amid drop in gas...from page 1Similarly, gas prices in SPP averaged about $2.66/MMBtu in

September, down 12 cents/MMBtu from August and $1.24/MMBtu

from 2014. Wind generation, however, accounted for almost 14%

of market share in September, up from 9% in August, driving

spark spreads at SPP North Hub down almost $4/MWh from

August to settle at $16.81/MWh.

PJM and CAISO also saw falling spark spreads in September,

however, these declines were the result of regional gas price

increases. Gas prices for generators in the PJM Western region also

climbed 21% over August to hit $1.42/MMBtu in September.

Average gas pr

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