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ANALYSIS

[ELECTRIC POWER ]

MEGAWATT DAILY

Monday, March 4, 2013

GE places bet on improved market conditions

General Electric is making a bet of up to $750 million that market conditions will improve for its 1,884-MW Homer City plant in western Pennsylvania. As a coal-fired generator in the PJM Interconnection, where generation fueled by cheap natural gas often sets the price for wholesale power, Homer City has been struggling for years. The plant's margins dropped to less than $1/MWh last year, from a high of $33/MWh as recently as 2007, Moody's Investors Service senior analyst Clifford Kim has said. In fact, Edison Mission Energy, which used to control the plant, was not making enough money to cover its lease payments to GE, so it handed over control to GE Capital on December 14. And the company that held the plant's debt, Homer City Funding, entered Chapter 11 bankruptcy late last year, emerging in

Price trends at key trading points ($/MWh)

300 250 200 150 100 50 0 18-Jan Source: Platts 28-Jan 05-Feb 13-Feb 21-Feb 01-Mar Mass Hub PJM West Into Southern ERCOT North Mid-C

Low and high average day-ahead LMP for Mar 2 ($/MWh)

ISONE NYISO PJM MISO ERCOT CAISO On-peak low 36.66 35.30 33.60 31.25 32.06 38.71 On-peak high 37.57 49.37 41.28 34.79 35.12 54.21 Off-peak low 29.90 27.89 28.98 25.18 26.36 34.51 Off-peak high 31.16 34.40 34.27 26.94 27.68 40.17

(continued on page 16)

ERCOT supply tight this summer: report

Available generation will exceed expected demand in the Electric Reliability Council of Texas by only about 8.4% this summer, a preliminary assessment of resource adequacy released Friday shows. The independent system operator expects to hit a peak demand of 67,998 MW, based on a weather outlook similar to 2010 and a slow-growth economic forecast, the preliminary Seasonal Assessment of Resource Adequacy for summer 2013 states. ERCOT expects to have 73,708 MW of generation capacity before taking into account forced power plant outages, which typically total about 2,600 MW during a day. "Current estimates indicate that we will likely see very tight conditions on the hottest days," said Kent Saathoff, ERCOT vice

SUPPLY (continued on page 17)

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

Day-ahead bilateral indexes and spark spreads for Mar 4

Index Northeast Mass Hub N.Y. Zone-A PJM/MISO PJM West Indiana Hub 47.50 37.00 44.25 37.00 Marginal heat rate 9514 10082 12275 10179 11002 8814 9513 15035 @7k 12.55 11.31 19.02 11.56 14.28 6.33 8.85 28.73 Spark spreads @8k @10k @12k 7.56 7.64 15.41 7.92 10.71 2.84 5.33 25.15 -2.43 0.30 8.20 0.65 3.58 -4.14 -1.72 18.00 -12.41 -7.04 0.99 -6.62 -3.56 -11.12 -8.76 10.85 @15k -27.39 -18.05 -9.83 -17.53 -14.26 -21.59 -19.33 0.13

Southeast and central Southern, Into 39.25 ERCOT, North 30.76 West Mid-C SP15 33.51 53.75

FERC, Barclays still at odds on probe

It may be a while before the Federal Energy Regulatory Commission can close the books on its market manipulation investigation of Barclays Bank and four of its former traders given that one trader is fighting a commission subpoena in court and the bank itself has refused to provide any more materials, according to documents the commission recently made public. FERC in October proposed to hit Barclays with a record-setting $435 million civil penalty and make the bank disgorge $34.9 million, plus interest, in profits it made when it allegedly manipulated energy markets in and around California. The commission alleged that Barclays and four of its former traders -- Scott Connelly, Daniel Brin, Karen Levine and Ryan Smith -- "engaged in a coordinated scheme to manipulate

TRADING (continued on page 18)

Note: Spark spreads are reported in ($) and Marginal heat rates in (Btu/kWh). A full listing of bilateral indexes and marginal heat rates are availible inside this issue.

Inside this Issue

Market gets better look at PJM data on generation Exelon, ICEA appeal ICC's FutureGen ruling SCE&G eyes possible options to handle supply gap Westar exercises caution on gas switching PUCT continues to eye resource adequacy Ontario outlook highlights renewable gains Total California power generation fell in February Coal's share of PJM fuel mix gains

12 13 14 14 15 15 16 16

The McGraw Hill Companies

Megawatt daily

Monday, March 4, 2013

NORThEAST MARkETS

Northeast day-ahead bilateral indexes for Mar 4 ($/MWh)

Index Change -9.00 2.50 2.75 0.50 1.25 0.25 0.50 0.75 0.25 0.75 Avg $/Mo 52.00 45.75 46.63 36.75 28.88 35.88 31.75 32.13 29.63 22.38 Marginal heat rate 9514 11026 11261 10082 7499 7211 7507 7625 8106 5783 On-peak Mass Hub N.Y. Zone-G N.Y. Zone-J N.Y. Zone-A Ontario* Off-Peak Mass Hub N.Y. Zone-G N.Y. Zone-J N.Y. Zone-A Ontario*

*Ontario prices are in Canadian dollars

Dailies mixed; terms down

Northeast dailies were mixed in for-Monday trading on IntercontinentalExchange Friday morning amid lower spot gas prices on the ICE offset by forecast increasing demand. Terms in the region were mostly lower as the NYMEX April natural gas futures settled 3 cents lower at $3.456/MMBtu Friday. Algonquin city-gates spot natural gas was trading around $5.00/ MMBtu on ICE, down $1.69, while natural gas at Tennessee-Zone 6 was trading around $4.98/MMBtu, a drop of $1.25. Transco Zone 6 New York spot natural gas was trading around $3.82/MMBtu, down 5 cents. The temperature forecast in New England for Monday was seen as mixed. Boston was expected to see a high of 44 on Monday compared with a projected high of 40 for Friday, while Hartford, Connecticut, was expected to see slightly cooler temperatures from Friday. Weekend highs across the region were expected to range from the mid-30s to mid-40s.ISO New England forecast the peak load for Monday at 18,060 MW, up 910 MW from Friday's projected peak load. The forecast peak load for Saturday and Sunday was 16,300 MW and 16,730 MW, respectively. Mass Hub day-ahead peak for Monday delivery was trading around $47.50/MWh, down $9. Day-ahead offpeak was bid at $30 and offered at $38/MWh, down about $1.75. Mass Hub weekend peak traded around $42.75/MWh. Weekend offpeak was bid at $30.50 and offered at $32/MWh. At 10:30 a.m. EST, the real-time price for Mass Hub power was $42.65/MWh. In New York state, high temperatures for Monday were forecast from the upper 20s to lower 40s, a few degrees cooler than Friday's highs. New York City was expected to see a high of 42 on Monday, down 5 degrees from Friday's projected high. Weekend highs across the state were expected to range from the mid-20s to mid-40s. The New York-ISO forecast the peak load for Monday at 21,091 MW, up 954 MW from Friday's projected peak load. The forecast peak load for Saturday and Sunday was 18,881 MW and 19,025 MW, respectively. NYISO Zone-G day-ahead on-peak was bid at $46.50 and offered at $50.85/MWh, up about $4. Zone-G weekend peak was bid at $42.50 and offered at $49/MWh. NYISO Zone-A day-ahead peak was bid at $36 and offered at $43/MWh, up about $3.Day-ahead peak prices for Saturday cleared lower in the ISO-New England auction on Friday while off-peak prices were higher. The ISO forecast peak demand to drop about 5% to around 16,300 MW on Saturday before increasing to 16,730 MW on Sunday. Internal Hub peak cleared at $37.42/MWh, down $9.87, while off-peak cleared at $30.78/MWh, up $2.21. Peak for NE Mass-Boston cleared at $37.57, down $10.56, while off-peak cleared at $30.85, up $1.85. Peak for SE Mass came in at $37.53, a drop of $10.54, and off-peak came in at $30.79, a gain of $1.86. Connecticut peak cleared at $36.94/MWh, down $6.86, and off-peak cleared at $30.60/MWh, up $3.26. Rhode Island peak came in at $37.46/MWh, a drop of $10.69, while off-peak cleared at $30.85, a gain of $1.66. The highest hourly day-ahead price was $49.12/MWh for NE Mass-Boston for the hour ending 7 p.m.

47.50 47.00 48.00 37.00 29.50 36.00 32.00 32.50 29.75 22.75

Northeast spot natural gas prices ($/MMBtu)

40 35 30 25 20 15 10 5 0 16-Jan 25-Jan 04-Feb 12-Feb 21-Feb 01-Mar Iroquois zone 2 Transco zone 6 N.Y. Algonquin city-gates

Source: Platts

ISONE fuel cost comparision ($/MMBtu)

25 20 15 10 5 0 15-Jan 24-Jan 01-Feb 11-Feb 20-Feb 28-Feb Gas Coal Oil

Source: Platts

Northeast load and generation mix forecast (GWh)

Actual 01-Mar ISONE Load 308 Generation Coal 15 Gas 100 Nuclear 109 NYISO Load 389 Generation Coal 12 Gas 100 Nuclear 135

Source: Bentek Analytics

% Chg %Chg Year-ago -7 2 -25 0 -6 26 -25 0 3 25 -18 2 3 34 -10 5

Forecast 02-Mar 03-Mar 04-Mar 05-Mar 06-Mar 310 15 101 110 389 15 95 135 316 16 108 110 390 15 100 135 347 15 115 110 434 16 108 135 350 14 116 110 435 16 112 135 352 15 118 110 432 14 115 135

(continued on page 10)

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copyright © 2013 the Mcgraw-hill companies

Megawatt daily

Monday, March 4, 2013

ISONE day-ahead LMP for Mar 2 ($/MWh)

Hub/Zone On-peak Internal Hub Connecticut NE Mass-Boston SE Mass West-Central Mass Rhode Island Maine New Hampshire Vermont Off-Peak Internal Hub Connecticut NE Mass-Boston SE Mass West-Central Mass Rhode Island Maine New Hampshire Vermont 30.78 30.60 30.85 30.79 30.89 31.16 29.90 30.53 30.41 0.00 0.00 1.85 0.00 0.00 0.00 1.22 1.71 0.00 0.08 -0.10 0.00 0.09 0.19 0.46 0.00 0.00 -0.29 2.21 3.26 0.15 1.86 2.40 1.97 -0.80 -0.16 2.64 29.68 28.97 4999 29.86 29.69 30.18 5774 5896 29.09 4901 5743 4903 4919 4962 37.42 36.94 37.57 37.53 37.47 37.46 36.66 37.19 36.78 0.00 0.00 -10.56 0.00 0.00 0.00 -10.59 -10.31 0.00 0.15 -0.33 0.00 0.26 0.20 0.19 0.00 0.00 -0.49 -9.87 -6.86 0.31 -10.54 -9.58 -10.69 -0.61 -0.08 -8.54 42.36 40.37 7171 42.80 42.26 42.81 7666 7786 41.05 7223 7550 7244 7233 7230 Average Cong Loss Change Avg $/Mo Marginal heat rate

Northeast Platts-ICE Forward Curve, Mar 1 ($/MWh)

Prompt month: Apr 13 Mass Hub N.Y. Zone G N.Y. Zone J N.Y. Zone A Ontario*

*Ontario prices are in Canadian dollars

On-peak 44.00 43.75 46.50 37.50 27.25

Off-peak 34.75 32.50 33.50 28.75 19.00

Mass Hub: Forward curve ($/MWh)

7982

100 80 60 40 20

6709

0

NYISO day-ahead LMP for Mar 2 ($/MWh)

Hub/Zone On-peak Capital Zone Central Zone Dunwoodie Zone Genesee Zone Hudson Valley Zone Long Island Zone Millwood Zone Mohawk Valley Zone N.Y.C. Zone North Zone West Zone Off-Peak Capital Zone Central Zone Dunwoodie Zone Genesee Zone Hudson Valley Zone Long Island Zone Millwood Zone Mohawk Valley Zone N.Y.C. Zone North Zone West Zone 30.65 29.18 31.26 28.88 31.13 34.40 31.23 29.88 31.44 27.89 28.91 0.00 0.00 0.00 0.00 0.00 -1.92 0.00 0.00 0.00 0.00 0.00 1.88 0.41 2.49 0.11 2.37 3.71 2.46 1.11 2.67 -0.88 0.14 -0.74 -0.61 -0.53 -0.60 -0.57 -2.29 -0.56 -0.95 -0.43 -0.58 -0.54 31.02 29.49 31.53 29.18 31.42 35.55 31.51 30.36 31.66 28.18 29.18 7263 8016 7399 7935 7368 8141 7391 7393 7440 6154 7944 39.76 37.16 41.17 36.24 40.82 49.37 41.12 38.49 41.80 35.89 35.30 -0.03 0.00 -0.02 0.00 -0.02 -6.82 -0.02 0.00 -0.38 0.00 0.00 2.64 0.06 4.06 -0.86 3.71 5.45 4.00 1.39 4.32 -1.21 -1.80 -5.36 -3.12 -4.98 -2.65 -4.93 -10.10 -5.00 -3.95 -4.61 -3.08 -2.17 42.44 38.72 43.66 37.57 43.29 54.42 43.62 40.47 44.11 37.43 36.39 9306 10133 9671 9881 9588 11596 9658 9407 9819 7789 9626 Average Cong Loss Change Avg $/Mo Marginal heat rate

Mass Hub: Marginal heat rate (Btu/kWh)

11500 Month 1 Month 2 10625

9750

8875

8000 14-Jan

Northeast near-term bilateral markets ($/MWh)

Package Mass Hub Bal-week Bal-month (off-peak) Next-week Next-week Next-week (off-peak)

*Ontario prices are in Canadian dollars.

Generation unit outage report

Plant/Operator Northeast Bruce-4/Bruce Bruce-6/Bruce Darlington-4/OPG Pickering-1/OPG Cap 740 825 878 452 Fuel n n n n State Ont. Ont. Ont. Ont. Status MO PMO PMO PMO Return Unk Unk Unk Unk Shut 08/02/12 02/15/13 02/04/13 09/26/12

Daily generation outage references

MO unplanned maintenance outage RF refueling outage PMO planned maintenance outage Unk unknown OA offline/available Fuels: Nuclear=n; Coal=c; Natural gas=g; Hydro=h ; Wind=w

Sources: Generation owners, public information and other market sources.

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copyright © 2013 the Mcgraw-hill companies

Ap M r-13 ay Ju -13 n Ju Se -13 l/ p-1 Au 3 gQ4 13 M -13 ay Ju -14 n Ja Se -14 n p M /Fe -14 ar b Ju /Ap 14 l/ r-1 Au 4 gQ4 14 M -14 ay Ju -15 n Ja Se -15 n p M /Fe -15 ar b Ju /Ap 15 l/ r-1 Au 5 gQ4 15 Ca -15 l Ca -14 l Ca -15 l Ca -16 l-1 7

23-Jan 01-Feb 11-Feb 20-Feb 01-Mar

Trade date 03/01 03/01 03/01 02/28 02/28

Range 51.00-52.00 44.75-45.25 58.00-60.00 62.75-63.25 44.75-45.25

Megawatt daily

Monday, March 4, 2013

SOUThEAST MARkETS

Southeast & Central day-ahead bilateral indexes for Mar 4 ($/MWh)

Index Change 6.00 6.00 6.00 5.50 5.00 3.75 4.00 2.50 3.50 4.00 -3.73 -3.50 -3.25 -3.50 -1.35 -1.25 -2.00 -1.25 2.00 3.25 2.25 3.00 Avg $/Mo 37.50 36.25 36.00 36.00 33.25 31.81 31.50 30.38 30.63 29.00 32.63 32.50 32.38 31.75 24.32 24.31 24.25 24.06 33.50 32.38 29.44 28.25 Marginal heat rate 10672 11002 9824 10794 10200 8630 9110 7809 8774 8559 8814 8868 8853 8837 6871 6921 6838 6996 9583 9869 8333 8418 Southeast On-peak VACAR Southern, Into Florida TVA, Into Entergy, Into Southeast Off-Peak* VACAR Southern, Into Florida TVA, Into Entergy, Into ERCOT On-peak ERCOT, Houston ERCOT, North ERCOT, South ERCOT, West ERCOT Off-Peak* ERCOT, Houston ERCOT, North ERCOT, South ERCOT, West SPP/MRO On-peak MAPP, Soth SPP, North SPP/MRO Off-Peak* MAPP, Soth SPP, North

*Off-peak is for Saturday-Monday delivery.

Dailies post mixed results; terms end flat

Southeast dailies finished mixed, and terms were flat on Friday. The NYMEX April natural gas futures settled 3 cents lower at $3.456/MMBtu. Electric Reliability Council of Texas dailies for Monday delivery were weaker on IntercontinentalExchange Friday morning with peak load forecast dropping and temperatures forecast rising. Spot natural gas at Houston Ship Channel was steady around $3.463/MMBtu. ERCOT North Hub next-day on-peak physical power for Monday delivery shed about $3.75 to trade around $30.75/MWh. Off-peak for Saturday-Monday delivery lost about $1.25 to trade around $24/ MWh. Weekend was trading around $31/MWh. West Hub on-peak for Monday delivery was offered at $29, $4.50 below Thursday prices. High temperatures across ERCOT were forecast in the mid-50s to mid-60s over the weekend before jumping to the mid-70s Monday. The average March high temperature across ERCOT is in the upper 60s to the mid-70s. System load in ERCOT was forecast to peak at 42,350 MW Friday and 38,325 MW Saturday, compared with an actual peak of 40,752 MW Thursday. ERCOT forecast peak load at 35,600 MW Monday. Real-time prices averaged $30.25/MWh and were flat from 12:15 to 6 a.m. CST Thursday. Wind generation was forecast to peak at 4,725 MW at 6 p.m. CST Friday and 3,250 MW at midnight CST Saturday. North Hub balance-of-the-week on-peak packages were bid at $29.50 and offered at $31.50/MWh. Next-week on-peak was bid at $30 and offered at $32.75. Balance-of-the-month on-peak packages were bid at $29.50 and offered at $34/MWh. In other South Central markets, Into Entergy next-day for Monday delivery was bid at $30/MWh, 75 cents below Thursday prices. Off-peak for Saturday-Monday delivery was bid at $25/ MWh, $1 below Thursday prices. Weekend was bid at $30/MWh. High temperatures across Entergy's footprint were forecast in the mid-40s to mid-50s over the weekend, and the upper 50s to upper 60s Monday. The average March temperature across Entergy is in the mid-60s to low 70s.

(continued on page 11)

40.50 39.25 39.00 38.75 35.75 32.75 32.50 31.00 31.50 30.00 30.76 30.75 30.75 30.00 23.98 24.00 23.75 23.75 34.50 34.00 30.00 29.00

Southeast load and generation mix forecast (GWh)

Actual 01-Mar ERCOT 794 Load Generation Coal 371 Gas 288 Nuclear 91 SPP Load 636 Generation Coal 466 Gas 120 Nuclear 19

Source: Bentek Analytics

% Chg %Chg Year-ago -1 6 -13 0 2 4 -1 0 3 13 -7 3 2 9 -19 41

Forecast 02-Mar 03-Mar 04-Mar 05-Mar 06-Mar 785 372 297 91 631 481 123 19 744 359 288 91 595 442 115 19 750 340 273 91 583 419 108 19 749 338 272 91 598 433 109 19 769 344 281 91 595 436 106 19

Southeast fuel cost comparision ($/MMBtu)

4.0 Gas Coal

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

4.0 Panhandle, Tx. Okla. Houston Ship Channel Henry Hub

3.5

3.5

3.0 15-Jan

24-Jan

01-Feb

11-Feb

20-Feb

28-Feb

3.0 16-Jan

25-Jan

04-Feb

12-Feb

21-Feb

01-Mar

Source: Platts

Source: Platts

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copyright © 2013 the Mcgraw-hill companies

Megawatt daily

Monday, March 4, 2013

ERCOT average day-ahead LMP for Mar 2 ($/MWh)

Hub/Zone On-peak Bus Average Hub Average Houston Hub North Hub South Hub West Hub AEN Zone CPS Zone LCRA Zone Rayburn Zone Houston Zone North Zone South Zone West Zone Off-Peak Bus Average Hub Average Houston Hub North Hub South Hub West Hub AEN Zone CPS Zone LCRA Zone Rayburn Zone Houston Zone North Zone South Zone West Zone 26.39 26.39 26.39 26.40 26.38 26.37 26.41 26.43 26.41 26.40 26.39 26.40 26.36 27.68 0.02 0.04 0.01 0.00 0.10 0.05 -0.02 -0.05 -0.04 -0.03 0.01 -0.02 0.14 -1.61 26.38 26.37 26.39 26.40 26.33 26.35 26.42 26.46 26.43 26.42 26.39 26.41 26.29 28.49 7658 7658 7635 7617 7626 7762 7772 7659 7655 7617 7637 7617 7622 8147 32.53 32.45 32.55 32.66 32.40 32.15 32.70 32.90 32.73 32.76 32.57 32.70 32.06 35.12 -0.92 -0.66 -1.09 -1.16 -0.85 0.43 -0.95 -0.91 -0.96 -2.15 -1.07 -1.55 -1.04 -1.27 32.99 32.78 33.10 33.24 32.83 31.94 33.18 33.36 33.21 33.84 33.11 33.48 32.58 35.76 9410 9387 9391 9368 9331 9464 9624 9484 9436 9397 9398 9382 9232 10338 Average Change Avg $/Mo Marginal heat rate

Southeast & Central Platts-ICE Forward Curve, Mar 1 ($/MWh)

Prompt month: Apr 13 Southern Into Entergy Into ERCOT North Houston ERCOT West ERCOT South On-peak 32.00 29.50 36.25 39.50 37.25 34.75 Off-peak 26.50 23.75 26.00 27.25 25.25 23.50

Into Southern: Forward curve ($/MWh)

50 40 30 20 10 0

Into Southern: Marginal heat rate (Btu/kWh)

10000

9625

9250

Southeast & Central near-term bilateral markets ($/MWh)

Package ERCOT, North Bal-week Next-week Trade date 02/27 02/27 Range 34.50-35.00 30.75-31.25

8875

8500 14-Jan

Generation unit outage report

Plant/Operator Southeast & Central Browns Ferry-3/TVA Crystal River-3/Progress Fort Calhoun/OPPD Hatch-2/Southern River Bend/Entergy South Texas-2/NRG Turkey Point-3/FP&L Turkey Point-4/FP&L Vogtle-2/Southern Wolf Creek-1/Wolf Creek Cap 1113 838 526 921 992 1413 825 693 1215 1226 Fuel n n n n n n n n n n State Ala. Fla. Neb. Ga. La. Tex. Fla. Fla. Ga. Kan. Status MO MO RF RF RF MO MO PMO MO PMO Return Shut

Unk 02/25/13 Retired 09/26/09 Unk 04/11/11 Unk 02/11/13 03/14/13 02/16/13 Unk 01/08/13 Unk 02/11/13 Unk 11/05/12 Unk 02/27/13 03/30/13 02/04/13

Market coverage

Platts provides a detailed methodology related to its coverage of North American electricity markets at: http://platts.com/MethodologyAndSpecifications/ElectricPower. Questions can be directed to Mike Wilczek, Market Editor, (202) 383-2246, [email protected]

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Ap M r-13 ay Ju -13 n Ju Se -13 l/ p-1 Au 3 gQ4 13 M -13 ay Ju -14 Ja S n-1 n/ ep 4 M Fe -14 ar b-1 Ju /Ap 4 l/ r-1 Au 4 gQ4 14 M -14 ay Ju -15 n Ja Se -15 n p M /Fe -15 ar b Ju /Ap 15 l/ r-1 Au 5 gQ4 15 Ca -15 l Ca -14 l Ca -15 l Ca -16 l-1 7

Month 1 Month 2 23-Jan 01-Feb 11-Feb 20-Feb 01-Mar

Megawatt daily

Monday, March 4, 2013

WEST MARkETS

Western day-ahead bilateral indexes for Mar 4 ($/MWh)

Index Change 3.14 3.77 1.69 0.25 1.75 0.00 1.75 4.00 2.10 1.16 0.76 0.75 0.25 1.00 2.75 5.50 Avg $/Mo 32.80 31.00 30.31 31.83 30.83 30.00 41.33 51.08 30.80 28.59 27.43 29.13 26.63 27.25 35.63 40.50 Marginal heat rate 9983 9513 9009 8951 9343 8811 11199 15035 9113 8281 7968 8252 7810 8150 9750 12098 On-peak COB Mid-C Palo Verde Mead Mona Four Corners NP15 SP15 Off-Peak* COB Mid-C Palo Verde Mead Mona Four Corners NP15 SP15

*West off-peak includes all day Sunday.

Dailies finish mostly higher; terms end mixed

Western dailies were mostly up Friday with colder weather forecast and mixed spot natural gas prices. Terms ended mixed, and NYMEX April natural gas futures settled 3 cents lower at $3.456/MMBtu. In the Northwest, Mid-Columbia day-ahead on-peak rose about $3.75, trading between $32.50 and $34.75/MWh for delivery on Monday. Mid-C day-ahead off-peak prices climbed more than $1 with trades between $28 and $31/MWh for delivery on Sunday and Monday with the inclusion of Sunday peak hours. The Mid-C on-peak balance-of-the month package was bid at $32.50 and offered at $32.75/MWh. Portland, Oregon, temperatures forecasts fell with highs retreating from the low 60s on Friday to low 50s by Sunday before rebounding to the low 60s Monday. Lows were dropping from around 50 to the high 30s through the weekend and hitting the low 40s on Monday. The Bonneville Power Administration's wind generation at 7 a.m. PST Friday was 2,079 MW and hydropower was 7,891 MW. In California, SP15 next-day on-peak rose more than $4 to trade between $53.50 and $55/MWh. SP15 day-ahead off-peak jumped more than $5.25, trading between $42.50 and $45/MWh. SP15 on-peak bal-month was bid at $50 and offered at $50.20/ MWh on IntercontinentalExchange. NP15 day-ahead on-peak was near flat at about $40.75/MWh. NP15 day-ahead off-peak increased more than $2.50 to about $37/MWh. Sacramento, California, highs were expected to drop steadily from the upper 70s Friday to upper 60s on Monday. Lows were expected to range from the upper 40s to the low 40s. In Burbank, forecasts had highs falling from the low 80s to upper 60s on Monday. Lows were going from the low 50s to upper 40s. The California Independent System Operator projected peak demand to hit 28,488 MW on Friday and 26,502 MW on Saturday. Renewable generation was 2,010 MW and wind was about 150 MW at 7 a.m. PST on Friday. In the desert Southwest, Palo Verde next-day on-peak increased more than $1.50 to trade between $31.25 and $31.75/ MWh. Palo Verde day-ahead off-peak rose almost $1 with trades between $27.75 and $28/MWh. Palo Verde on-peak bal-month was bid at $29.50 and offered at $34/MWh. Phoenix highs were steady in the low 80s through Monday. Lows were rising from the low 50s to upper 50s. Next day natural gas prices in the Rockies and California were mixed. Opal fell 0.7 cents to $3.448/MMBtu and SoCal city-gate was down 2.8 cents to $3.712/MMBtu. Meanwhile, Pacific Gas and Electric city-gate rose 5.8 cents to $3.793/MMBtu. Day-ahead prices in the California ISO auction cleared mixed heading into the weekend, according to auction results from Friday. For northern California, NP15 on-peak cleared around $39.23/MWh, a drop of about 74 cents, while off-peak cleared

(continued on page 11)

34.89 33.51 31.44 32.00 32.00 30.00 42.50 53.75 31.85 29.17 27.81 29.50 26.75 27.75 37.00 43.25

Western spot natural gas prices ($/MMBtu)

4.0

3.5

NW, Can. Bdr. (Sumas) 3.0 16-Jan 25-Jan 04-Feb

SoCal Gas city-gate 12-Feb

PG&E city-gate 21-Feb 01-Mar

Source: Platts

Western fuel cost comparision ($/MMBtu)

3.5 3.0 2.5 2.0 1.5 1.0 0.5 15-Jan 24-Jan 01-Feb 11-Feb 20-Feb 28-Feb Gas Coal

Source: Platts

Western load and generation mix forecast (GWh)

Actual 01-Mar CAISO Load 652 Generation Gas 268 Nuclear 28

Source: Bentek Analytics

% Chg %Chg Year-ago 4 4 0 2 5 -40

Forecast 02-Mar 03-Mar 04-Mar 05-Mar 06-Mar 588 253 28 547 240 28 601 240 28 604 246 28 613 250 28

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copyright © 2013 the Mcgraw-hill companies

Megawatt daily

Monday, March 4, 2013

CAISO average day-ahead LMP for Mar 2 ($/MWh)

Hub/Zone On-peak NP15 Gen Hub SP15 Gen Hub ZP26 Gen Hub Off-Peak NP15 Gen Hub SP15 Gen Hub ZP26 Gen Hub 34.82 40.17 34.51 -2.58 2.40 -2.58 -0.75 -0.39 -1.06 0.71 -1.63 0.74 34.47 40.99 34.14 9286 11154 9583 39.23 54.21 38.71 -7.92 6.70 -7.92 -1.11 -0.75 -1.63 -0.74 -7.85 -0.56 39.60 58.14 38.99 10337 15165 10828 Average Cong Loss Change Avg $/Mo Marginal heat rate

Western Platts-ICE Forward Curve, Mar 1 ($/MWh)

Prompt month: Apr 13 Mid-C Palo Verde NP15 SP15 Mead On-peak 29.00 32.00 34.50 40.75 49.25 Off-peak 23.25 25.25 29.75 32.00 37.00

Mid-C: Forward curve ($/MWh)

50

Western near-term bilateral markets ($/MWh)

Package Mid-C Bal-month Bal-month (off-peak) SP15 Bal-month Trade date 03/01 03/01 03/01 Range 32.25-32.75 29.75-30.25 49.75-50.25

40 30 20 10 0

Plant/Operator West Alamitos-4/AES Alamitos-5/AES Colgate-2/PCWA Contra Costa-7/NRG Diablo Canyon-2/PG&E El Segundo-4/NRG Empire-2/Inland Empire Encina-4/Cabrillo Encina-5/Cabrillo Etiwanda-3/RRI Helms-2/PG&E Los Esteros/Calpine Mandalay-1/RRI Martinez Cogen Mexicali/Energia Azteca Mountainview-4 Ocotillo/Pattern Ormond Beach-2/RRI Pittsburg-7/NRG San Onofre-2/SCE San Onofre-3/SCE Sentinel/CPV Sunrise/Edison

Cap 336 498 337 337 1150 335 366 300 330 320 407 188 215 115 180 525 265 775 682 1124 1126 728 590

Fuel g g h g n g g g g g h g g g g g w g g n n g g

State Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif.

Status PMO PMO PMO MO PMO PMO MO PMO PMO PMO PMO PMO PMO PMO PMO PMO PMO PMO PMO PMO MO MO PMO

Return Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk

Shut 02/03/13 02/11/13 02/26/13 02/26/13 02/03/13 02/18/13 02/18/13 02/18/13 02/18/13 01/27/13 12/02/12 01/02/13 02/10/13 02/25/13 02/20/13 02/26/13 02/26/13 02/25/13 02/18/13 01/09/12 01/31/12 01/17/13 01/23/13

Mid-C: Marginal heat rate (Btu/kWh)

10000 Month 1 Month 2 9000

8000

7000

BPA & CAISO hydro and wind generation (GWh)

250 200 150 100 50 0 29-Jan 3-Feb 8-Feb 13-Feb 18-Feb 23-Feb 28-Feb BPA Hydro CALISO Hydro BPA Wind CALISO Wind

Additional information on data and analysis:

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

Source: BPA and CAISO

7

copyright © 2013 the Mcgraw-hill companies

Ap rM 13 ay -1 Ju 3 n1 Q2 3 -1 Q3 3 -1 Q4 3 -1 Q1 3 -1 Q2 4 -1 Q3 4 -1 Q4 4 -1 Q1 4 -1 Q2 5 -1 Q3 5 -1 Q4 5 -1 Ca 5 l-1 Ca 4 l-1 Ca 5 l-1 Ca 6 l-1 7

Generation unit outage report

14-Jan

23-Jan

01-Feb

11-Feb

20-Feb

01-Mar

Megawatt daily

Monday, March 4, 2013

PJM & MISO MARkETS

PJM & MISO day-ahead bilateral indexes for Mar 4 ($/MWh)

Index Change 6.00 7.50 3.00 3.50 3.00 3.75 1.50 2.25 3.75 -1.00 0.50 -2.25 2.50 2.25 3.75 0.25 Avg $/Mo 41.25 43.00 38.25 36.25 32.25 32.88 30.75 28.38 35.13 34.25 31.50 29.88 27.25 27.63 25.38 24.88 Marginal heat rate 12275 12644 11119 10411 9362 9398 8811 8082 10179 9240 8765 7893 7840 7871 7522 6863 PJM On-peak PJM West Dominion Hub AD Hub NI Hub PJM Off-Peak PJM West Dominion Hub AD Hub NI Hub MISO On-peak Indiana Hub Michigan Hub Minesota Hub Illinios Hub MISO Off-Peak Indiana Hub Michigan Hub Minesota Hub Illinios Hub

Dailies mostly up; terms softer

Power prices for Monday delivery in the Midwest Independent Transmission System Operator and the PJM Interconnection regions were mostly higher Friday. Forwards were softer as the NYMEX April natural gas futures settled 3 cents lower at $3.456/MMBtu Friday. Mid-Atlantic dailies were higher in for-Monday trading on IntercontinentalExchange as Texas Eastern M-3 spot natural gas traded around $3.84/MMBtu on ICE, up 10 cents. The PJM Interconnection projected peak load at 108,858 MW for Monday, up about 6% from Friday. Forecasts called for lower temperatures, with highs from the lower 30s to the upper 40s. PJM West Hub day-ahead peak was trading around $44/MWh, up $5.75. Dayahead off-peak was bid at $31.50/MWh, up 75 cents, and offered at $36/MWh. Weekend peak was bid at $36.25 and offered at $36.75/MWh, down $1.50 from Thursday bids. Weekend off-peak was bid at $30.50 and offered at $33/MWh. Midwestern dailies were higher as Chicago city-gates spot natural gas traded around $3.67/MMBtu on ICE, up 3 cents. Temperatures were expected to rise, with highs from the lower 30s to the mid-40s. Wind generation in the MISO footprint was forecast to peak at 4,163 MW on Saturday. Real time wind generation was about 3,260 MW around 10 a.m. EST. Indiana Hub day-ahead peak was trading around $37/MWh, up $3.75. Dayahead off-peak was trading near $28.50/MWh, up $2.50. Weekend peak was trading near $31.50/MWh, up $1 from Thursday trades. Weekend off-peak was bid at $27 and offered at $28/MWh. Dailies were mixed in the Midwestern portion of PJM. AEPDayton Hub day-ahead peak was bid at $38.50/MWh, up $1.75. Dayahead off-peak was bid at $30/MWh, unchanged. Weekend peak was bid at $33.50 and offered at $35.75/MWh, up 25 cents from Thursday bids. Weekend off-peak was bid at $30.25 and offered at $33/MWh. Northern Illinois Hub day-ahead peak was bid at $36/MWh, up $1.50, and offered at $40.70/MWh. Day-ahead off-peak was bid at $24/MWh, down $3.25. Weekend peak was bid at $31.25 and offered at $34/MWh, down 50 cents from Thursday offers. Weekend off-peak was bid at $26 and offered at $27/MWh. PJM day-ahead clearing prices were mixed Friday according to auction results from the Mid Atlantic grid operator. The PJM Interconnection projected peak load for Saturday at 98,176 MW, down about 5% from Friday. Day-ahead prices in the PJM footprint averaged $36.88/MWh for peak, down 59 cents from the day prior, while off-peak prices averaged around $31.77/MWh, up 81 cents. The PJM West Hub day-ahead peak price cleared around $37.70/ MWh, down 36 cents, while off-peak cleared at $32.26/MWh, up $1.39. AEP-Dayton Hub's price cleared at $36.12/MWh, down 83 cents. The day-ahead price for the Northern Illinois Hub cleared around $34.20/MWh, down 42 cents. Dominion Hub came in with the highest day-ahead price at $40.08/MWh, up 97 cents. The highest day-ahead zonal price cleared at PEPCO zone for $41.26/MWh, up 76 cents. Congestion prices across the region were fairly soft, with prices for hubs ranging from negative $1.78/MWh to $2.88/MWh, while zone

44.25 46.75 39.75 38.00 33.75 34.75 31.50 29.50 37.00 33.75 31.75 28.75 28.50 28.75 27.25 25.00

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

12 10 8 6 4 2 16-Jan 25-Jan 04-Feb 12-Feb 21-Feb 01-Mar Chicago city-gates Columbia Gas App Tx.Eastern, M-3

Source: Platts

PJM fuel cost comparision ($/MMBtu)

4.0 Gas Coal

3.5

3.0

2.5 15-Jan

24-Jan

01-Feb

11-Feb

20-Feb

28-Feb

Source: Platts

PJM & MISO load and generation mix forecast (GWh)

Actual 01-Mar PJM Load 2055 Generation Coal 853 Gas 295 Nuclear 777 MISO Load 1583 Generation Coal 1382 Gas 64 Nuclear 195

Source: Bentek Analytics

% Chg %Chg Year-ago -1 1 -9 0 5 6 1 1 4 12 -13 1 3 10 -31 -5

Forecast 02-Mar 03-Mar 04-Mar 05-Mar 06-Mar 2044 892 304 777 1438 1290 69 195 2080 903 322 779 1350 1211 71 195 2317 929 331 783 1473 1190 73 195 2302 958 326 787 1476 1210 68 195 2225 938 313 789 1467 1237 55 195

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Monday, March 4, 2013

MISO average day-ahead LMP for Mar 2 ($/MWh)

Hub/Zone On-peak Indiana Hub Michigan Hub Minesota Hub Illinios Hub Off-Peak Indiana Hub Michigan Hub Minesota Hub Illinios Hub 26.91 26.94 26.63 25.18 0.54 0.07 1.73 0.26 0.73 1.24 -0.72 -0.71 0.40 0.63 2.33 2.45 26.71 26.63 25.47 23.96 7409 7411 7356 6914 34.79 34.34 33.75 31.25 2.02 1.21 1.02 0.08 0.28 0.64 0.24 -1.32 -3.38 -0.83 0.32 1.26 36.48 34.76 33.59 30.62 9561 9403 9312 8579 Average Cong Loss Change Avg $/Mo Marginal heat rate

PJM average day-ahead LMP for Mar 2 ($/MWh)

Hub/Zone On-peak AEP Gen Hub AEP-Dayton Hub ATSI Gen Hub Chicago Gen Hub Chicago Hub Dominion Hub Eastern Hub New Jersy Hub Northern Illinios Hub Ohio Hub West Internal Hub Western Hub AEP Zone Allegheny Power Zone Atlantic Elec Zone ATSI Zone BG&E Zone ComEd Zone Dayton P&L Zone Delmarva P&L Zone Dominion Zone Duke Zone Duquesne Light Zone JCPL Zone MetEd Zone PECO Zone Pennsylvania Elec Zone PEPCO Zone PPL Zone PSEG Zone Rockland Elec Zone Off-Peak AEP Gen Hub AEP-Dayton Hub ATSI Gen Hub Chicago Gen Hub Chicago Hub Dominion Hub Eastern Hub New Jersy Hub Northern Illinios Hub Ohio Hub West Internal Hub Western Hub AEP Zone Allegheny Power Zone Atlantic Elec Zone ATSI Zone BG&E Zone ComEd Zone Dayton P&L Zone Delmarva P&L Zone Dominion Zone Duke Zone Duquesne Light Zone JCPL Zone MetEd Zone PECO Zone Pennsylvania Elec Zone PEPCO Zone PPL Zone PSEG Zone Rockland Elec Zone 34.38 36.12 35.81 33.60 34.51 40.08 36.62 36.99 34.20 36.27 36.95 37.70 36.26 36.99 36.11 35.99 41.28 34.37 36.78 36.68 40.42 34.32 34.04 36.15 38.29 35.32 36.14 41.26 34.33 37.48 37.89 30.49 31.58 31.54 28.98 29.72 33.31 32.27 31.71 29.48 31.66 31.86 32.26 31.64 32.12 31.62 31.68 34.27 29.59 32.11 32.36 33.48 30.31 30.30 31.70 31.72 31.28 31.63 34.04 30.56 31.77 31.68 -1.03 -0.38 -0.89 -1.15 -0.89 2.88 -1.78 -0.79 -1.01 -0.29 0.38 0.81 -0.26 0.11 -1.86 -0.98 2.93 -0.94 -0.67 -1.68 2.99 -1.49 -1.32 -1.91 1.56 -1.86 -0.94 3.11 -2.26 -0.12 0.52 -0.03 0.27 0.14 -0.81 -0.59 0.60 -0.61 -0.59 -0.67 0.34 0.29 0.33 0.22 0.22 -0.67 0.10 0.95 -0.63 0.17 -0.58 0.65 -0.38 -0.02 -0.74 0.13 -0.62 -0.17 0.85 -0.86 -0.48 -0.32 -1.47 -0.37 -0.18 -2.12 -1.47 0.33 1.52 0.90 -1.66 -0.32 -0.30 0.02 -0.35 0.01 1.09 0.09 1.47 -1.56 0.58 1.49 0.55 -1.07 -1.51 1.19 -0.14 0.31 0.21 1.27 -0.29 0.73 0.50 -1.24 -0.46 -0.36 -1.96 -1.46 0.95 1.13 0.54 -1.61 -0.44 -0.18 0.17 -0.34 0.13 0.52 -0.18 1.56 -1.54 0.18 1.18 1.06 -1.07 -1.45 0.69 -0.17 0.14 0.04 1.43 -0.35 0.49 0.23 -0.80 -0.83 -0.99 -0.37 -0.43 0.97 -1.38 -2.41 -0.42 -0.81 -0.25 -0.36 -0.66 -0.43 -1.10 -1.01 0.74 -0.46 -0.87 -1.53 0.95 -0.82 -1.03 -1.13 -0.92 -1.25 -1.57 0.76 -1.46 -3.43 -4.10 0.78 0.73 0.82 1.46 1.42 1.39 0.21 0.00 1.47 0.74 0.99 0.63 0.82 0.85 0.29 0.81 1.01 1.41 0.82 0.14 1.33 0.99 0.67 0.13 0.80 0.29 0.20 1.17 -0.07 -0.10 -0.17 34.78 36.54 36.31 33.79 34.73 39.60 37.31 38.20 34.41 36.68 37.08 37.88 36.59 37.21 36.66 36.50 40.91 34.60 37.22 37.45 39.95 34.73 34.56 36.72 38.75 35.95 36.93 40.88 35.06 39.20 39.94 30.10 31.22 31.13 28.25 29.01 32.62 32.17 31.71 28.75 31.29 31.37 31.95 31.23 31.70 31.48 31.28 33.77 28.89 31.70 32.29 32.82 29.82 29.97 31.64 31.32 31.14 31.53 33.46 30.60 31.82 31.77 9462 9943 9897 9210 9458 10846 9624 9721 9374 9988 10266 10473 9980 10238 9489 9948 11247 9420 10108 9639 10939 9432 9460 9501 10249 9454 10076 11243 9187 9850 9958 8442 8743 8797 7960 8161 9127 8583 8434 8097 8767 8954 9065 8761 8959 8409 8835 9446 8127 8842 8606 9171 8348 8517 8432 8588 8469 8897 9381 8273 8449 8425 Average Cong Loss Change Avg $/Mo Marginal heat rate

PJM & MISO near-term bilateral markets ($/MWh)

Package PJM West Bal-week Bal-week Bal-week Next-week Next-week Next-week Next-week Trade date 03/01 02/27 02/25 03/01 02/27 02/26 02/25 Range 42.00-42.50 38.50-39.00 36.00-36.50 39.75-40.25 43.25-43.75 43.50-44.00 45.00-45.50

Generation unit outage report

Plant/Operator PJM & MISO Calvert Cliffs-2/CENG LaSalle-2/Exelon Cap 880 1150 Fuel n n State Md. Ill. Status RF RF Return Unk Unk Shut 02/17/13 02/11/13

]

COMMODITY PULSE VIDEO

Energy security: Europe at the crossroads

Featuring Richard Swann, John Roberts, & Henry Edwardes Evans In this video Richard Swann, John Roberts and Henry Edwardes Evans discuss how despite recent falls in power demand, Europe is undergoing a huge period of change regarding its energy portfolio; why the "golden age of gas" has not transpired; why coal, as an indirect consequence of the US shale gas boom, has become unexpectedly competitive; whether a sudden upturn in demand could expose deep rooted supply & infrastructural issues; & the potential impact of shale on the UK gas market. http://plts.co/pcpese

9

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Monday, March 4, 2013

congestion prices ranged from negative $2.26/MWh to $2.99/MWh. MISO day-ahead prices cleared lower than the day prior, according to auction results issued late Friday. Indiana Hub peak prices cleared at $32.44/MWh, up 73 cents, while off-peak cleared at $27.66/MWh, up $2.12. The hub that cleared with the highest day-ahead price was Michigan Hub at $32.31/MWh, down 99 cents. The hub with the lowest day-ahead clearing price was Minnesota Hub at $28.63/MWh, down 83 cents. Illinois Hub peak cleared around $29.05/MWh, down 41 cents. MISO footprint day-ahead prices averaged $29.24/MWh for peak, down $1.07 from the day prior. Off peak footprint prices averaged $26.47/MWh, up $4.35. Mid-Atlantic forwards were softer Friday with a dip in gas futures. PJM West on-peak April financial futures were 50 cents weaker with bids at $41.75 and offers at $41.95/MWh on ICE at about 2:30 p.m. EST. PJM West on-peak May shed 25 cents to about $43.25/MWh while on-peak July-August edged down 25 cents to about $55.50/MWh. PJM West off-peak April gave up 25 cents, falling to about $30.25/MWh. Midwest forward markets were tame Friday as gas futures edged down. AD Hub on-peak April financial futures fell 50 cents to about $38.25/MWh. AD Hub on-peak July-August packages were 25 cents weaker at about $49.75/MWh. Indiana Hub on-peak April dropped 50 cents to about $34/MWh while Indiana Hub on-peak July-August came down 25 cents to about $45/MWh. NI Hub on-peak April was unchanged at about $35/MWh. NI Hub on-peak July-August shed 25 cents to about $47.75/MWh.

PJM & MISO Platts-ICE Forward Curve, Mar 1 ($/MWh)

Prompt month: Apr 13 PJM West AD Hub NI Hub Indiana Hub On-peak 41.75 38.25 35.00 34.00 Off-peak 30.25 28.25 23.25 26.25

PJM West: Forward curve ($/MWh)

60 50 40 30 20 10 0

PJM West: Marginal heat rate (Btu/kWh)

12500 12300 12100 11900 11700 11500 Month 1 Month 2 14-Jan 23-Jan 01-Feb 11-Feb 20-Feb 01-Mar

Northeast markets ... from page 2

Day-ahead clearing prices for Saturday were lower in the New York Independent System Operator auction Friday. The NYISO projected demand for Saturday to drop about 6.2% to around 18,881 MW, before climbing to 19,025 MW for Sunday. Day-ahead peak prices for the Hudson Valley Zone dropped $4.93, clearing at $40.82/MWh. Off-peak cleared at $31.13/MWh, down 57 cents. New York City Zone peak came in at $41.80/MWh, down $4.61, while off-peak cleared at $31.44, a drop of 43 cents. Long Island Zone peak cleared at $49.37/MWh, a drop of $10.10, and off-peak cleared at $34.40/MWh, a loss of $2.29. West Zone peak cleared at $35.30/MWh, down $2.17, while off-peak fell 54 cents to clear at $28.91/MWh. Central Zone peak cleared at $37.16/MWh, down $3.12, while off-peak came in at $29.18/MWh, down 61 cents. The Mohawk Valley Zone peak cleared at $38.49/MWh, down $3.95, and off-peak cleared at $29.88/MWh, down 95 cents. The highest hourly day-ahead price was $56.36/MWh for the New York City Zone for the hour ending at 7 p.m. The auction results showed little congestion was expected across the grid for Saturday. Northeast term power was mostly down Friday. In New England, Mass Hub on-peak April financial futures tumbled $3 with bids at $43.75 and offers at $44.25/MWh on ICE at about 2:30 p.m. EST. Mass Hub on-peak May dropped 75 cents to about $42.75/MWh while on-peak July-August came down $1.75 to about $53.75/MWh. Mass Hub off-peak April sank $2.50 to about $34.75/MWh. New York Zone G on-peak April fell 75 cents to about $43.75/MWh. New York Zone A on-peak April added 25 cents to about $37.50/MWh.

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Ap M r-13 ay Ju -13 n Ju Se -13 l/ p-1 Au 3 gQ4 13 M -13 ay Ju -14 n Ja Se -14 n p M /Fe -14 ar b Ju /Ap 14 l/ r-1 Au 4 gQ4 14 M -14 ay Ju -15 n Ja Se -15 n p M /Fe -15 ar b Ju /Ap 15 l/ r-1 Au 5 gQ4 15 Ca -15 l Ca -14 l Ca -15 l Ca -16 l-1 7

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Southeast markets ... from page 4

In the Southeast, dailies for Monday delivery were firmer Friday morning with temperatures forecast increasing along with spot gas prices. Into Southern next-day on-peak power for Monday delivery climbed up $5.75 to trade around $39/MWh. Weekend was bid at $33 and offered at $37/MWh. Spot natural gas at Transco Zone-3 rose 3.5 cents to around $3.560/MMBtu. High temperatures in Atlanta were forecast in the mid-40s over the weekend, before rising to the mid-50s Monday. The average March high temperature in Atlanta is 65, with an average low of 44. The Electric Reliability Council of Texas day-ahead clearing prices for Saturday were weaker Friday, with the exception of the west, as peak load was expected to decrease. Spreads between hubs tightened day-to-day with the West Hub and North Hub moving from a more than $2 spread Thursday to about a 50-cent spread Friday. North Hub on-peak cleared in the ERCOT auction at $32.66/ MWh, down nearly $1.25 from Friday's day-ahead market, while offpeak was unchanged at $26.40/MWh. Houston Hub on-peak cleared the ERCOT auction at $32.55/MWh, roughly $1 below Friday's dayahead market, while off-peak cleared at $26.39/MWh, nearly steady. South Hub on-peak cleared the ERCOT auction at $32.40/ MWh, a loss of about 75 cents, while off-peak cleared at $26.38/ MWh, nearly flat. West Hub on-peak cleared in the ERCOT auction at $32.15/MWh, rising about 50 cents, while off-peak cleared at $26.37/MWh, nearly steady. The highest hourly dayahead price occurred at 9 a.m. in the North Hub at $45/MWh. All other hubs were in the mid-$40s/MWh. ERCOT system load was forecast to peak at 38,325 MW Saturday, down 10% from Friday?s expected peak of 42,350 MW.

South Central April terms were flat to down. ERCOT Houston on-peak April fell 50 cents to about $39.50/ MWh, and July-August dropped $1 to about $89/MWh. Heat rates were down about 40 Btu/kWh on ICE around 2:30 p.m. EST. ERCOT North April fell 50 cents to about $36.25/MWh, May moved up 50 cents to about $36.50/MWh, and July-August lost $1 to about $89.50/MWh. Into Entergy April was unchanged at about $29.50/MWh, and July-August edged down 20 cents to about $35.15/MWh. Southeast on-peak April was flat. Into Southern April stayed at about $32/MWh, May fell 25 cents to about $33.25/MWh, and July-August inched down 10 cents to about $37.90/MWh.

West markets ... from page 6

around $34.82/MWh, a rise of about 71 cents. In Southern California, SP15 on-peak cleared around $54.21/MWh, a drop of about $7.84 and off-peak cleared aruond $40.17/MWh, a loss of about $1.63. For ZP26, on-peak cleared around $38.71/MWh, about 57 cents lower and off-peak rose 74 cents to $34.51/MWh. In the Northwest term markets, Mid-C on-peak April was unchanged with bids at $28.75 and offers at $29/MWh on ICE around 2:30 p.m. EST. The second quarter crept down 10 cents to about $25.90/MWh, and the third quarter inched down 15 cents to about $38.75/MWh. In California, SP15 on-peak April financial terms gained 50 cents with bids at $49 and offers at $49.50/MWh. Q2 rose 40 cents to about $48.40/MWh, and Q3 climbed 50 cents to about $56.85/MWh. NP15 April stayed at about $40.75/MWh, and the second quarter fell 35 cents to about $40.15/MWh. Palo Verde April shed 75 cents to about $32/MWh, Q2 edged down 10 cents to about $34.90/MWh, and Q3 stayed at about $43.15/MWh.

]

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NEWS

Market gets better look at PJM data on generation

Market participants in the PJM Interconnection are reviewing newly available data indicating more precisely the level of back-up generation supporting demand response resources and what it means for the future of demand response activities. The amount of back-up generation being used to support demand response participants, who can use their own generation resources while reducing their use from the power grid, has been a point of contention and an unknown quantity in independent system operators for some time. It has had particular scrutiny in PJM, which has the largest demand response market among the ISOs. The Electric Power Supply Association, PJM Power Providers and others are looking at recent data from PJM and sifting through the numbers and their implications, officials said recently. The information posted by PJM on its website about the level of back-up generation and demand response activities stems from the ISO's effort to make its demand response program more transparent, said Gary Helm, the organization's senior market strategist. Generator groups and others have been seeking more information from PJM, which has been trying to collect more data from customers and demand response providers. The activity report posted recently represents "the fruit of that labor," Helm said in an interview. PJM will post the information in monthly reports, as demand response firms register their customer sites and commit resources to meet their obligations stemming from the three-year-forward capacity auction in PJM, Helm explained. ISO New England does not break down its demand response resources by customer type or business segment as PJM is doing, spokeswoman Marcia Blomberg said. Questions about the amount of back-up generation that supports demand response resources have come not only from generators who compete with the resources but from the PJM market monitor and state environmental agencies. The Northeast States for Coordinated Air Use Management last year said "the increasing attractiveness of back-up diesel engines' use in demand response programs has the potential to undermine successful efforts to date" in reducing air pollution, while noting that a precise inventory of diesel generators enrolled in demand response programs was not available because of the number of generator sites, different types of demand response programs and confidentiality concerns of market participants. The Environmental Protection Agency earlier this year imposed cleaner fuel requirements beginning in 2015 for dieselfueled reciprocating internal combustion engines and operating limits for such engines that are used in emergency demand response programs, among other requirements. EPA said the rule would apply to back-up diesel engines that have not installed emission controls, limiting their hours and calling on

owners to submit annual reports on their locations and operating information. PJM indicated for the first time that 22.6% of its emergency demand response program in the current delivery year has backup generation, and that 67% of the back-up generation runs on diesel fuel, with 15% fueled by natural gas and much smaller percentages using other fuels. PJM does not know how many of the diesel units have emission controls on them, which would exempt them from the EPA rule. "We are not getting into that level of detail," which will be tracked by either EPA or the state environmental agencies, Helm said. The data shows that currently, 8,548 MW of emergency demand response capacity is in the market, meaning about 1,930 MW has back-up generation. Other sources of demand response capacity at customer sites include 27.5% from manufacturing processes, 22% from heating, ventilation and air conditioning systems, 5.8% from lighting, almost 19% categorized as "other" and smaller percentages in refrigeration and water heating. The figures do not represent capacity expectations from the forward auction in PJM but "what is actually in the marketplace now," said Helm. When companies bid into the auction "they do not have to tell us exactly where and what that demand response is" until just before they register for the delivery year, he said. While industrial customers and manufacturing represents the biggest segment of demand response suppliers at 46%, residential customers are the next biggest segment at 14%, with schools at 7%, office buildings at 6%, hospitals at 4% and various other segments at smaller percentages, the PJM data shows. One of the biggest contributors, spread out among many utilities within PJM is small customers that cut back on their air conditioning load, which likely explains the large residential representation, Helm said. The PJM data also indicates that of the revenue generated in the demand response program, the vast majority comes from capacity payments for customers to be available to shed load, regardless of whether they respond when an event is called. For 2011, about $500,000 in revenue was projected in the program, with capacity payments accounting for more than $450,000 and regulation and ancillary services accounting for much lower payments. But that is not to say DR firms do not respond when called upon, Helm said, referring to data mentioned by CEO Terry Boston last week at a White House event touting demand response markets. PJM has seen a seven-fold increase in DR resources taking part in the forward auctions over the past five years, with last year's auction procuring more than 14,000 MW of those resources on top of 923 MW of energy efficiency resources, Boston said. He acknowledged that he has concerns about "response fatigue" or whether the demand response resources can be counted on when grid reliability is at risk, and in various tests and actual events, with a few exceptions, the

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resources have been available when called upon. The level of demand response clearing PJM's forward auction also has attracted the attention of Monitoring Analytics, PJM's independent market monitor, which in December issued a report showing that demand response firms regularly purchased replacement capacity for a substantial portion of their market commitments from June 2007 to June 2011. Joseph Bowring, president of Monitoring Analytics, said the practice raises questions about forward capacity auctions and whether PJM should cap the amount of demand response or seek more information on DR firms' capability to provide resources. EPSA is pleased that PJM is providing more transparency on the demand response market, and the group will closely watch the developments, particularly as the EPA rule begins to take effect, said John Shelk, president and CEO of EPSA. When demand response is supported by diesel generators, it could result in "dirty" demand response supplanting PJM generation resources, including natural gas-fired power plants, Shelk said in an interview. If the amount of demand response in the capacity market is not being called on, it raises the question of why it is in the capacity market, as Bowring pointed out in his report, Shelk said. -- Tom Tiernan

RGGI carbon allowance futures, Feb 28 ($/allowance)

ICE Dec13 Dec13 Dec13 Dec13 Dec14 Dec14 Dec14 Dec14 Dec15 Dec15 Dec15 Dec15 V09 V10 V11 V12 V09 V10 V11 V12 V09 V10 V11 V12 Settlement 2.75 2.75 2.75 2.75 2.75 2.75 2.75 2.75 2.75 2.75 2.75 2.75 Volume 0 0 0 200 0 0 0 0 0 0 0 0 NYMEX GE Dec13 Dec14 Settlement 1.97 1.97 Volume 0 0

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

Daily CSAPR allowance assessments, Mar 1

CSAPR ($/st) SO2 Group 1 SO2 Group 2 NOx Annual NOx Seasonal

All prices in $/st

2013 Range 5.00-35.00 25.00-75.00 40.00-70.00 20.00-90.00

Mid 20.00 50.00 55.00 55.00

2014 Range 5.00-25.00 25.00-65.00 30.00-70.00 20.00-80.00

Mid 15.00 45.00 50.00 50.00

Exelon, ICEA appeal ICC's FutureGen ruling

The long-delayed FutureGen clean coal project in Illinois faces another hurdle, this one in the form of legal action by a group of competitive power suppliers and Commonwealth Edison that challenges state regulatory approval of a rate surcharge for the proposed 166-MW plant. ComEd, an Exelon subsidiary and the state's largest electric utility, and the Illinois Competitive Energy Association are asking the state Appellate Court to set aside the Illinois Commerce Commission's December 19 order that cleared the way for the Illinois Power Agency to buy power from the so-called FutureGen 2.0 plant at above-market rates. ICEA's appeal was filed Thursday, ComEd's about a week ago. ICEA, in particular, argues the ICC lacks legal authority to require alternative retail electric suppliers and utilities to enter into sourcing agreements with a specific private company. ComEd's appeal left Senator Dick Durbin of Illinois fuming. Durbin, a longtime FutureGen supporter and the Senate's Assistant Majority Leader, accused Chicago-based Exelon of betrayal in the twisting and turning FutureGen saga. Exelon, owner of the nation's largest nuclear fleet -- in excess of 18,000 MW of generating capacity -- has worked with the FutureGen Alliance in recent years. With wholesale power prices still in the tank, Exelon's critics say the company is trying to block all would-be competitors, including FutureGen, from entering the state. On Friday, Exelon spokesman Paul Elsberg disagreed with Durbin's reference to Exelon's "resignation" from the alliance, whose members include some of the world's largest privately owned coal companies, headed by the largest, St. Louis-based Peabody Energy. "Importantly, Exelon did not formally join or contribute to the FutureGen Alliance," Elsberg said. "Rather, we decided not to

Daily CAIR allowance assessments, Mar 1

$/allowance SO2 2013 0.74 Change 0.00 $/st 1.48

For methodology, visit www.emissions.platts.com. Full coverage of SO2 and NOx emissions markets now appears in Platts Coal Trader. For information on Coal Trader, contact [email protected] platts.com or call 1-800-PLATTS-8.

join the restructured alliance, which has changed significantly since we announced our intention to join in early 2010." Exelon's appeal decision, he added, "reflects our long-held position that customers should not be forced to pay enormous above-market charges for electricity, as the project is now seeking." An Illinois coal official, who asked not to be identified, scoffed at the notion Exelon is worried about customer power bills, branding the company's stance hypocritical at best. Exelon, he recalled, pushed through the General Assembly in late 2011 a controversial smart grid and electric infrastructure bill. Governor Pat Quinn vetoed the legislation, voicing concern about consumer protections and future rate increases, but legislators overrode his veto. ICEA consistently has objected to the IPA's proposal to purchase power from FutureGen 2.0, a unit at Ameren Illinois's Meredosia power plant that would be retrofitted with oxycombustion technology to essentially eliminate all air emissions. Carbon dioxide from the plant would be captured and transported through an approximately 30-mile-long pipeline to an underground storage site elsewhere in Morgan County. Kevin Wright, ICEA president and former ICC chairman, said in an interview his group's appeal "attempts to protect our municipal aggregation, business, and public sector customers from this unlawful FutureGen order and attack on the

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competitive retail electric market." The ICC, he asserted, has "absolutely no statutory authority to compel competitive supply customers to shoulder the costs and subsequent rate hikes from this unneeded, above-market and 20-year guarantee project." ICEA also is expected to tell the court that state law does not give the ICC the right "to require that [competitive suppliers] or their customers finance the construction of a facility," in this instance the Meredosia retrofit. Exelon Energy, the competitive arm of Exelon, is an ICEA member, along with Constellation NewEnergy, Direct Energy, Integrys Energy Services, FirstEnergy Solutions, MC Squared Energy Services, Nordic Energy Services, Ameren Energy Marketing, Champion Energy and Reliant. The Retail Energy Supply Association, a national trade group, also opposed inserting FutureGen into the IPA plan. RESA unsuccessfully urged the ICC to strip FutureGen from the plan, claiming the Meredosia plant's power would be too expensive. FutureGen spokesman Lawrence Pacheco said the alliance believes the ICC's order will stand on appeal. "Appeals are a normal part of the process and this will be resolved in due time," he said. Meanwhile, "FutureGen 2.0's development activities will continue without disruption." Current plans call for construction to begin early next year, with the plant up and running in mid-2017. -- Bob Matyi and Derek Sands

SCE&G eyes possible options to handle supply gap

South Carolina Electric & Gas is exploring at least three alternatives for bridging a potential power-supply gap between the April 2015 compliance date for the Mercury and Air Toxics Standards rule and the estimated March 2017 commercial startup of the first of two new nuclear units, SCE&G said Friday. SCE&G's "first option," said utility spokesman Robert Yannity, would be to convert another four older coal steam units totaling 540 MW to natural gas firing and continue operating them -- and the 95-MW Urquhart steam unit, which was converted to gas firing in late 2012 -- until one or both of the two 1,117-MW V.C. Summer nuclear units now under construction comes online in March 2017 and May 2018. SCE&G holds a 55%, or 614-MW, ownership interest in each of the planned nuclear units; Santee Cooper owns the remaining 45%. Yannity said another option would be for SCE&G to ask the Environmental Protection Agency to delay the date by which the utility would need to retire its four coal steam units -- the 115MW Canadys-2, 180-MW Canadys-3, and McMeekin-1 and -2, each of which has a capacity of 125 MW -- to bring the utility into compliance with MATS. "Compliance with MATS is required within three years" of its April 2012 effective date, SCE&G said in the 2013 integrated resource plan the utility filed at the South Carolina Public Service Commission on Thursday. "A one-year extension may be granted by the state permitting authorities if additional time is needed for units

that are required to run for reliability purposes which would otherwise be deactivated, or which, due to factors beyond the control of the owner/operator, have a delay in installation of controls or need to operate because another unit has had such a delay." It continued, "A second year of extension may also be possible for reliability critical units that qualify for an administrative order at the end of the one-year extension. All extension requests must be supported by the written concurrence of the appropriate planning authority and will be considered by EPA on a case-by-case basis." Still another alternative, Yannity said Friday, would be for SCE&G to retire the coal steam units by April 2015 to comply with MATS, and replace their capacity with short-term power purchases. The IRP indicates SCE&G's preference for either refiring the coal steam units with gas and keeping them operational to either 2017 or 2018, or securing extensions for MATS compliance. The plan calls for retiring the two Canadys coal steam units in 2017 and the two McMeekin coal steam units and the Urquhart gas steam unit in 2018. If either approach to extending the operation of the steam units works, SCE&G expects to need to purchase only 25 MW of firm capacity in 2015 and 175 MW in 2016. If it needs to retire one or more of the coal steam units in 2015 or 2016 it presumably would need to purchase additional short-term power. In addition to its plan to add 614 MW of nuclear capacity in 2017 and 614 MW of nuclear capacity in 2018, SCE&G plans to add 93 MW of gas-fired peaking capacity each year from 2022 through 2026. With the steam unit retirements, planned nuclear and gasfired additions, and demand-side management factored in, SCE&G expects that its reserve margin over the next 15 years to range between 14.2% and 19.5%. In 2013, the reserve margin will be 16.8%; it will sag to 14.6% in 2014, 14.2% in 2015 and 14.3% in 2016 before rising to 15.8% and 19.5% in 2017 and 2018, respectively, when the new nuclear units come online. -- Housley Carr

Westar exercises caution on gas switching

Westar Energy is bucking the coal-to-gas switching trend among utilities and -- for cost reasons -- is maintaining its strong bias toward coal-fired and nuclear baseload generation, Topeka, Kansas-based Westar said Friday. "We're certainly taking advantage of lower [natural] gas prices, but not so much that we forget that any commodity ebbs and flows, and we're in this for the long term," Westar President and CEO Mark Ruelle said during an earnings conference call with energy analysts. He said that while all the capacity added to the utility's generation portfolio in the past 25 years has been either gas-fired or renewable -- and gas units now represent 41% of Westar's total non-wind capacity --"our customers still benefit from our baseload generation." Also, unlike many other utilities, Westar is not retiring any coal units to comply with the Environmental Protection Agency's Mercury and Air Toxics Standards rule. Ruelle noted that virtually all of the utility's coal-fired capacity is fitted with equipment to

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minimize sulfur dioxide and nitrogen oxide. According to Westar's new 10-K filing to the Securities and Exchange Commission, 74% of the electricity generated by the utility in 2012 came from its coal units, while 15% came from its share of the Wolf Creek nuclear unit, 9% came from gas units and 2% came from wind farms. In 2011, 77% of Westar's energy came from coal units, 13% from nuclear, 8% from gas and 2% from wind. Westar's weighted average cost of fuel, including transportation costs, favors nuclear and coal by wide margins, though the gap between coal and natural gas narrowed significantly in 2012. Last year the utility's fuel cost/MWh for nuclear and coal was $7.28 and $20.59, respectively, compared with $33.29 for gas; in 2011, Westar's fuel cost/MWh for nuclear, coal and gas was $7.15, $19.30 and $52.65, respectively. Westar's fourth quarter wholesale sales totaled 2.238 million MWh, a 3.3% decline from the same period in 2011. Tariff-based wholesale sales fell 2.8% to 1.354 million MWh, while marketbased sales fell 4% to 974,000 MWh. The average price Westar garnered for its market-based sales in the quarter was $25.33/ MWh, a 13% drop from a year earlier. -- Housley Carr

PUCT continues to eye resource adequacy

The Texas Public Utility Commission continues to look into interim solutions for resource adequacy across the state. Although no action was taken during Friday's PUCT meeting, Chairwoman Donna Nelson said she is continuing to work with the Electric Reliability Council of Texas and its independent market monitor to determine the effects of the interim solutions already presented. "In a competitive market where private investment is at risk, I think it is unwise for us to move forward without fully understanding any proposal, and appreciating the intended, and potential unintended, consequences that flow out of the proposal," Nelson said in a memo Thursday. "As we attempt to attract new generation investment to Texas, we need to be mindful of the effect that the new rules will have on existing generation and on electric customers." Harvard professor William Hogan, research director of the Harvard Electricity Policy Group, has presented a proposal to improve the efficiency of scarcity pricing through changes in the pricing of energy and operating reserves, Nelson stated in a memo filed Thursday. Hogan's proposal is built on a market that provides for the real time co-optimization of energy and ancillary services. Since the ERCOT market does not provide for the real time cooptimization of energy and ancillary services, John Dumas with ERCOT developed two interim solutions to improve scarcity pricing by using reserve demand curves, Nelson said in the filing. Interim solution A calls for scarcity pricing in the real-time energy market by modifying generator offer curves, while interim solution B calls for scarcity pricing in the real-time energy market

by valuing remaining operating reserves. At a January 24 workshop, Commissioner Kenneth Anderson asked ERCOT staff to come up with calculations of what the adder might have been given the conditions and the amount of reserves at the time using 2011 and 2012 data to determine the effect that interim solution B would have on scarcity pricing in the ERCOT market. ERCOT and Hogan continue to work to modify interim solution B to address incentive issues identified at the workshop, Nelson said in her filing. ERCOT will present a revised interim solution B proposal and backcast no later than March 21, one week before the PUCT's next open meeting, Nelson said. As it is not feasible to implement interim solution B by this summer, Anderson asked during the February 14 PUCT meeting if ERCOT could relook at interim solution A and determine if it could go online by this summer. "While I understand some stakeholders favor implementation of an interim solution prior to this summer, I do not think such a solution can be developed, vetted by stakeholders, and implemented within that timeframe," Nelson said in the filing. "Furthermore, it seems to be putting the cart before the horse to move forward with an interim solution before deciding to move forward with permanent implementation." -- Kassia Micek

Ontario outlook highlights renewable gains

More than 3,200 MW of renewable energy capacity will be integrated into Ontario's bulk power system by August 2014, according to the province's Independent Electricity System Operator. The added capacity includes Ontario's first two transmission grid-connected solar projects and an influx of wind generation in summer 2014 totaling more than 1,000 MW, the IESO said in releasing its 18-month outlook Thursday. By August 2014, total wind and solar grid-connected generation will total approximately 6,800 MW, the IESO said. "Integrating renewable resources into Ontario's changing supply mix has been a learning process for both us and the renewable generators," said Bruce Campbell, IESO vice president of resource integration, in a news release. "Everything we've learned will be applied in the coming months as wind and solar gain even more prominence on the grid." The IESO is moving toward an economic dispatch of gridconnected renewable resources, which it expects to be in place within the 18-month forecast period. Progress also continues toward the provincial government's goal of eliminating coal-fired generation, the report said, as the remaining units at Lambton and Nanticoke are set to stop burning coal by the end of the year, and the Atikokan generating station is in the process of being converted from a coal-fired unit to biomass. The unit is expected to be in service by the third quarter of 2014. The report said Ontario will continue to have adequate generation and transmission capability to meet consumers' needs

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over the next 18 months and reserve requirements are expected to be met for all weeks under all weather scenarios. The IESO projects energy demand to drop by 0.6% in 2013 after increasing 0.4% in 2012. Any increase in demand from economic growth will be more than offset by reductions from conservation measures and increased production from embedded generation, the IESO said. Summer peaks are projected to decline over the forecast period as a result of the growth in embedded solar capacity, while winter peaks will show a slight increase, the report said. -- Allan Schilling

January, up from 34.93% in December, while down from its 36.54% share in January 2012. Wind generation within PJM rose to 2.53% of the fuel mix in January compared with 2.29% a year earlier, the data shows. January's wind supply was higher than the average for 2012, or 1.62% of overall generation. Wind generation fluctuated in over the past year due to its variable nature, providing as low as 0.55% in August. Hydro generation dropped 8% on the year and stood at 1.08% of overall generation, with January up 17% from December. -- T.L. Hamilton

Total California power generation fell in February

Total generation in the California Independent System Operator footprint fell more than 2 million MWh in February, according to data issued by the grid operator Friday. Total generation in February was about 16.5 million MWh, down from January's total of about 18.9 million MWh. The output last month was slightly lower compared with February 2012, when the total generation was around 16.8 million MWh. Total nuclear generation was 812,467 MWh or roughly half of January's output. The total nuclear generation in California continues to be less than half of output for the same period as 2011 as the 2,150-MW San Onofre Nuclear Generating Station remains offline. In addition, the 1,150-MW Diablo Canyon Unit 2 went offline indefinitely in February for planned maintenance. Total generation imports into the ISO footprint was about 4.5 million MWh, about 700,000 MWh lower than in January. Natural gas-fired generation continues to help meet the generation losses caused by the SONGS outage. Total thermal generation was about 7.7 million MWh in February, a drop of roughly 800,000 MWh compared with January. Hydroelectric generation was down about 200,000 MWh compared to January at about 1.3 million MWh. Total renewables generation was up month-to-month by more than 100,000 MWh to 2.1 million MWh. Wind generation jumped more than 250,000 MWh in February to 732,363 MWh. -- Martin Coyne

GE places bet on improved conditions ... from page 1

December as Homer City Generation, which is 90% held by a group of seven owners that are ultimately owned by a subsidiary of GE Capital, a unit of General Electric, and 10% owned by Metropolitan Life. For the first half of 2012, the last period for which publicly available data is available, the Homer City plant lost $86 million. The plant lost $26 million in the first half of 2011. In that same half-year period in 2012 the plant had a capacity factor of 56.2% and an average realized energy price of $31.53/ MWh against average fuel costs of $32.61/MWh. In 2011, Homer City lost $1.04 billion, which includes an impairment charge of $1.0323 billion. Without that charge, Homer City lost $8 million. In 2010 the plant had a gain of $114 million. Against this background GE is investing $700 million to $750 million to install scrubbers on the two unscrubbed units at the three-unit plant. The scrubbers are designed to allow those units to keep operating and selling power into the market after the onset of new, tighter Environmental Protection Agency emissions standards, including the Mercury and Air Toxics Standards rule that takes effect in 2015. But while the scrubbers will affect the emissions profile of the plant, they will have little effect on the environment in which the plant operates. According to Platts data, the average peak price in PJM West in 2010 was $53.71/MWh. In 2011 the average peak price was $51.98/MWh, and in the first half of 2012, the average peak price was $37.87/MWh. For full year 2012, the average peak price was $40.86/MWh. If Homer City was losing money with prices at those levels, the spot prices for PJM are certainly not encouraging. PJM West day-ahead on-peak has averaged $40.62/MWh since the beginning of the year, with a brief spike to $71.75/MWh in late January. With the exception of the spike, prices were between $29.50 and $49.25/MWh. According to documents filed with the Securities and Exchange Commission in October, the plant's owners expect peak power prices in the PJM market, which Homer City sells into, to rise to $55.63/MWh in 2017 from $42.19/MWh in 2013. They said that would increase the plant's revenues and allow it to begin to turn a profit with projected net income of $21.7 million in

Coal's share of PJM fuel mix gains

Coal supplied 44.71% of the PJM Interconnection's generation fuel in January, up from its 43.41% contribution in December. Coal's share of PJM's fuel mix also rose on the year from 43.36% in January 2012. PJM's fuel mix for January is the most recent data available. While natural gas gained ground in PJM over 2012, the fuel share dropped slightly to 14.33% of generation in January, down from 14.83% in December. Natural gas usage in January also came in lower than January 2012, when it accounted for 16.57% of the fuel mix. Meanwhile, nuclear use gained at 36.33% of the fuel mix in

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2016 and $76.9 million in 2017. But Platts forward prices for PJM West do not reach the $55/ MWh level until 2020. And in 2016 and 2017 Platts forward prices for PJM West are $49.50/MWh and $50.88/MWh, respectively. There are other factors that figure into whether or not the plant will make or lose money; for instance, outages in 2011 dropped the plant's capacity factor to 57.1%, from 66.8% in 2010. But the Platts forward prices for 2016 and 2017 are below the historical average for 2011, the year Homer City lost $8 million after excluding extraordinary items. And even though Homer City Generation has emerged from bankruptcy, its debt level is the same as when it entered bankruptcy, so there is little relief from debt load in sight except for the pay-in-kind, or PIK, feature that was put in place as a result of the pre-packaged bankruptcy. The PIK, which is in force until April 1, 2014, gives Homer City Generation the option of deferring interest payments by making payments in bonds instead. It "greatly reduces default risk," Moody's Kim has said, but it could also increase the future debt load on the plant by $111 million, or 17%. So while the PIK gives Homer City some breathing room, when it expires in 2014 it could raise the bar for the plant's owners. That is also around the time that the scrubber installation could be completed. GE does not have a firm date for the completion of the job, GE Energy Financial Services spokesman Andy Katell said. The job was on an expedited schedule, but after a federal court vacated the Cross State Air Pollution Rule, which was challenged by a group of petitioners that included the owners of Homer City, GE has been evaluating how to proceed, Katell said. According to Platts data, Homer City was already operating close to its allocated emission allowance levels. Implementation of CSAPR could have had a steep economic cost for the plant, forcing the owners to buy allowances and making its operation uneconomic. As it is, when scrubbers are installed on an existing coal plant there is usually a 1% to 2% reduction in electrical output because of the energy consumed by the scrubbers, so there is a reduction in overall efficiency, David Harris, vice president for air quality control service at Black & Veatch, said. There are also some additional O&M costs associated with scrubbers, he said. On the other hand, the new scrubbers will give the plant more fuel flexibility, Katell said, adding that GE is considering blending its fuel by buying coal from regions other than Appalachia, the plant's historical fuel source. In PJM, power plants do not live on energy prices alone. They also receive capacity payments through PJM's reliability pricing model, or RPM, auction. PJM runs the RPM every May for capacity to be delivered three years down the road. In 2010 and 2011 Homer City had capacity revenues of $114 million and $84 million, respectively. In those years, capacity prices were $110/MW-day for 2012, $133.37/MW-day for 2013, and $226.15/MW-day for 2014. At the beginning of February, PJM released its updated parameters for its upcoming RPM auction for the 2016-17 delivery year. The numbers prompted UBS analyst Julien Dumoulin-Smith to

lower his RPM estimates to $124 MW-day for the RTO as a whole, down from $136/MW-day last year, and to $157/MW-day for the tight MAAC region in eastern PJM, from $167.50/MW-day last year. Dumoulin-Smith said the decrease is the result of more new gas capacity clearing the auction, greater demand response penetration, and a weakened demand outlook. The prospects for Homer City may not seem bright, but given the alternatives, installing the scrubbers and looking forward to higher power prices may have been GE's best option. GE could have walked away from the plant and taken a loss, but that is an unpalatable option for any corporation. The fact that another affiliate of GE is an owner of 16% of Homer City's bonds may have been a factor in the decision. GE also could have tried to sell the plant, but in current market conditions coal plants are proving to be a hard sell. In its fourth-quarter earnings, Dominion Resources took a $731 million writeoff on its Brayton Point plant in Somerset, Massachusetts, after unsuccessful attempts to sell the plant, which has three coal-fired units totaling 1,095 MW and a 435-MW unit that can burn either natural gas or fuel oil. In the SEC filing, the owners of Homer City put the plant's hypothetical liquidation value at $82 million to $92 million. Under the circumstances, GE decided that investing the capital, booking the depreciation and waiting for a rebound in power prices was its best option. Prior to reaching that decision, GE looked at a range of other options, including repowering units 1 and 2 with natural gas and firing ethane, Katell said. "We concluded that installing a NID dry scrubber system is the most effective and economic approach for Homer City," adding that the repowering and boiler modification options were rejected because of "cost, technical issues and timing." The plant is well positioned as a large coal asset with the ability to sell into PJM as well as into the New York ISO, and the plant has its own coal preparation facility, enabling it to buy raw coal from local mines, which has traditionally provided low-cost energy, Katell said. "We believe in the Homer City Generating Station's long-term value and that installing pollution control equipment will enable it to continue to comply with environmental regulations," he said. "We have done our own internal valuations and engaged a third-party adviser, and believe that we will earn both a return of, and return on, our investment." -- Peter Maloney

ERCOT supply tight this summer: report ... from page 1

president for grid operations and system planning, in a prepared statement. "There is a significant chance that ERCOT will need to issue energy emergency alerts and appeal to consumers to reduce their energy use on some of those days." In a conference call Friday afternoon, Warren Lasher, ERCOT director of system planning, said ERCOT would continue to monitor the situation and, if necessary, call for mothballed generation to be returned to service this summer. The final summer SARA is to be released May 1. But a final Seasonal Assessment of Resource Adequacy for the

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spring indicates enough resources will be available to meet spring demand, as long as extreme weather events do not occur when generators are undergoing maintenance to prepare for summer. For this summer, Saathoff noted that ERCOT expects to have more generation on hand than it had in the summer of 2012, but "we also expect higher demand this year." Chris Coleman, ERCOT meteorologist, forecasts a hotter and drier summer than normal. "Although we don't anticipate prolonged heat waves like those in 2011, we expect conditions in many areas to be similar to 2012," Coleman said in a prepared statement. ERCOT set its all-time record peak on August 3, 2011, at 68,305 MW, but set new monthly peaks in June, July and September 2012. The ERCOT reports appear to have had no significant effect on forward power prices, as the on-peak ERCOT North Hub JulyAugust package closed around $89.25/MWh Friday, down $1.25. In the past year, ERCOT and the Public Utility Commission of Texas have implemented rules to increase the systemwide offer cap and the amount of time in which it would be implemented. On June 1, that number will climb from $4,500/ MWh to $5,000/MWh. An energy trader who asked to remain unidentified because he lacks permission to speak to the media said, "The summer [package] is pricing in roughly seven hours at the systemwide offer cap." This trader said he thinks Friday's release for the summer is a "reasonable early season assessment," but it also includes some "wishful thinking" in terms of slow economic growth and substantial availability of demand response. "The increasingly binary nature of this market, where ERCOT has ample reserves for nine months out of the year and a very likely shortage in the summer months with rising price caps ... make navigating the ERCOT market very difficult for both loads and generators in the summer months," the source said. "It is the belief by some that generators, especially those that may be going through a phased bankruptcy, will have a difficult time hedging these high-risk months at these very inflated prices." Energy Future Holdings, Texas' largest generator, has indicated a substantial risk of being unable to meet its debt obligations, which totaled $46.6 billion as of the end of 2012. But consumers face a similarly risky situation, the trader said. "Consumers are in essence being forced to hedge at very high summer prices" because if they don't, they risk going out of business, the source said. The ERCOT report assumes that only 8.7% of nameplate wind generation capacity could be depended upon during peak periods, but a recent loss-of-load probability study assumed that 32.9% of coastal wind generation and 14.2% of noncoastal wind generation could be depended upon at peak time. The 8.7% assumption is "outmoded," said an electricity market analyst who asked to remain anonymous because he was not authorized to speak to the media. A pilot program to encourage more consumers to contract to provide Emergency Response Service ­ either by providing

distributed generation capacity or reducing demand during energy shortages ­ has been extended through summer 2013, and the analyst estimates about 500 MW of this capacity could be added to the summer SARA. Another issue that makes the summer SARA perhaps unrealistically conservative, the source said, is that it assumes 869 MW of generation would be out for planned maintenance, but this could be "managed" on a few days' notice so that all resources would be available when needed. Since last summer, ERCOT has posted nonbinding real-time prices for the next hour on its website to encourage consumers ­ mainly industrial and commercial consumers on indexed pricing contracts ­ to reduce energy use when wholesale prices are expected to rise significantly. ERCOT also can contract to bring generation out of "mothballed" status, if emergency conditions are anticipated. ERCOT's latest Capacity, Demand, and Reserve Report forecasts its reserve margin to dip to 13.2%, which is below its 13.75% target, this summer, and continue falling thereafter. This planning reserve margin target is designed so that generation would cause a loss of load event no more than once every 10 years. Most load losses occur due to failures in the transmission or distribution system. The Public Utility Commission of Texas will conduct a workshop on March 14 regarding how to expand demandresponse in ERCOT and what inputs should be used in developing the Capacity, Demand, and Reserves Report. A January letter from the North American Electric Reliability Corp. asked ERCOT to address near-term and long-term concerns about ERCOT's dwindling reserve margin in a written plan by April 30 and invited ERCOT to discuss the document at the NERC board of trustees meeting on May 9. -- Mark Watson

FERC, Barclays still at odds on probe ... from page 1

trading" of day-ahead electricity at four major Western trading hubs to benefit Barclays' IntercontinentalExchange financial swap positions in those markets over a number of months from November 2006 through 2008. In addition to proposing to penalize the bank, the commission proposed to assign a $15 million penalty to Connelly and dole out a $1 million penalty each to Brin, Levine and Smith. Commission staff in January disclosed that Smith had asked a New York court to quash a enforcement staff subpoena to testify "about recently discovered conversations he had with a third party in which he explained and confessed Barclays' manipulative

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scheme and his participation therein." The court magistrate judge on January 25 recommended that Smith's request to quash the FERC subpoena be denied because the FERC notice of alleged violations policy is intended to let third parties inform enforcement staff of additional information relevant to the investigation. "If any third-party allegations are found to be meritorious, the staff may conduct further discovery and any new material issues that might affect the subject's culpability will be presented to the subject for his or her response," said Judge Christian Hummel of the US District Court of the Northern District of New York (FERC v Smith, 1:12-MC-00074). As of press time, Hummel had not issued a final verdict in the matter. But documents released by FERC on Monday indicate that Smith is not the only one refusing to give enforcement staff more information. According to the documents in the FERC proceeding (Docket No. IN08-8), Barclays asked the commission to quash enforcement staff's subpoena of materials and data the bank previously agreed to provide but now claims it does not have to because it believes FERC's issuance of a public notice of the investigation and its show-cause order terminated the proceeding. The July 2012 agreement between Barclays and staff said the bank would comply with the subpoena without the need for subpoena enforcement action, staff said in one document. "The

terms of the agreement were clear: Barclays would produce the requested materials, subject to certain limitations and modifications," staff said on January 21 in urging the commission to make Barclays comply with the agreement. Barclays now "all but ignores its negotiated agreement to comply with the subpoena. Rather, Barclays repeatedly characterizes its production of documents in response to the subpoena as voluntary," staff said. "In fact, the record shows Barclays repeatedly recognized and acknowledged its agreement with staff to produce the requested information, and its current characterization of its productions in response to the subpoena as `voluntary' is incomplete and misleading." "Allowing Barclays to breach its agreement with staff would reward obstinacy and gamesmanship, rather than promote good faith efforts between commission staff and investigative subjects to resolve disputes without intervention by the commission or the courts," staff said. Barclays' believes that its "trading was legitimate and in compliance with applicable law," company spokesman Marc Hazelton said in a statement. "FERC should reject the Office of Enforcement's recommendations, decline to assess any penalties, and terminate this matter without any further proceedings. If the FERC proceeds, we intend to vigorously defend this matter in federal court," he said. -- Esther Whieldon

]

Paul Ciampoli News Desk 202-383-2254 Editor in Chief Rod Kuckro Editor Michael Fox

MEGAWATT DAILY

Market Editor Mike Wilczek Staff Reporters

Volume 18 / Issue 42 / Monday, March 4, 2013

ISSN # 1088-4319

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Megawatt daily

Monday, March 4, 2013

Weekly bilateral indexes for week ending Mar 2 ($/MWh)

Index Northeast On-peak Mass Hub N.Y. Zone-G N.Y. Zone-J N.Y. Zone-A Ontario* PJM On-peak PJM West Dominion Hub AD Hub NI Hub MISO On-peak Indiana Hub Michigan Hub Minesota Hub Illinios Hub Southeast On-peak VACAR Southern, Into Florida TVA, Into Entergy, Into ERCOT On-peak ERCOT, Houston ERCOT, North ERCOT, South ERCOT, West SPP/MRO On-peak MAPP, Soth SPP, North Western On-peak COB Mid-C Palo Verde Mead Mona Four Corners NP15 SP15

*Ontario prices are in Canadian dollars

Change -61.35 -52.45 -68.30 -4.15 -2.10 -5.20 -6.20 -2.45 -0.95 -1.80 -0.25 -6.40 -3.65 -1.90 -0.05 -1.60 -0.40 -0.50 3.51 3.50 3.30 5.70 -2.45 -2.10 4.06 4.53 0.85 1.41 1.92 0.58 2.54 4.34

Low 50.25 44.50 45.25 33.50 26.25 35.50 36.50 33.00 30.50 29.50 30.75 27.00 21.25 32.50 30.25 31.25 30.00 27.25 27.75 27.25 27.25 28.50 26.25 26.00 31.75 28.50 28.00 31.75 30.25 30.00 40.75 47.50

High 60.00 52.00 53.00 36.50 28.25 38.25 39.25 36.75 34.50 33.25 34.75 32.50 31.00 34.50 33.25 33.25 33.25 30.75 35.30 34.25 34.00 33.50 32.50 30.75 38.50 36.50 36.50 36.00 36.25 35.00 43.00 50.25 Northeast Off-Peak Mass Hub N.Y. Zone-G N.Y. Zone-J N.Y. Zone-A Ontario* PJM Off-Peak PJM West Dominion Hub AD Hub NI Hub MISO Off-Peak Indiana Hub Michigan Hub Minesota Hub Illinios Hub Southeast Off-Peak VACAR Southern, Into Florida TVA, Into Entergy, Into ERCOT Off-Peak ERCOT, Houston ERCOT, North ERCOT, South ERCOT, West SPP/MRO Off-Peak MAPP, Soth SPP, North Western Off-Peak COB Mid-C Palo Verde Mead Mona Four Corners NP15 SP15

Index 39.90 33.40 33.65 29.20 21.25 30.30 30.85 28.90 26.20 24.85 25.00 23.40 19.95 27.54 26.58 26.58 26.13 24.13 22.94 22.88 23.08 22.63 24.58 23.46 32.83 31.54 29.39 30.86 28.25 29.96 35.32 38.71

Change -46.00 -36.05 -38.80 -3.90 -2.75 -4.50 -4.80 -3.35 -1.05 -1.40 -2.65 -1.70 -1.50 -2.96 -1.96 -0.71 -2.00 -1.45 3.43 3.30 3.41 4.17 -2.17 -1.87 4.36 4.90 2.28 2.25 2.25 2.89 2.21 2.60

Low 35.75 30.75 31.00 28.00 20.75 28.75 30.25 27.25 24.25 23.25 22.00 21.25 14.50 26.75 26.00 26.00 25.25 22.50 21.20 21.50 21.75 21.50 22.00 21.25 29.75 27.50 27.00 28.75 26.50 26.75 34.25 37.25

High 47.00 39.50 39.75 31.00 22.00 32.00 32.25 30.25 27.25 26.00 26.50 25.00 24.75 29.00 28.50 28.50 28.00 26.00 26.00 25.25 25.75 25.00 27.75 26.00 37.00 35.75 31.75 35.50 30.25 34.50 37.00 41.25

56.55 47.75 48.40 35.00 27.30 36.75 37.35 34.70 32.65 31.20 32.50 29.80 25.95 33.50 32.30 32.10 32.05 29.65 30.58 30.30 30.15 30.50 29.65 28.80 34.79 32.52 31.94 33.71 33.21 32.25 41.46 49.17

Weekend bilateral indexes for Mar 2-3 ($/MWh)

Saturday Sunday Index Index Northeast On-peak Mass Hub N.Y. Zone-G N.Y. Zone-J N.Y. Zone-A Ontario* PJM On-peak PJM West Dominion Hub AD Hub NI Hub MISO On-peak Indiana Hub Michigan Hub Minesota Hub Illinios Hub Southeast On-peak VACAR Southern, Into Florida TVA, Into Entergy, Into 41.75 42.50 43.25 35.25 28.50 37.00 39.50 34.50 32.50 31.50 28.50 26.25 23.25 36.75 36.50 36.25 35.25 33.50 41.75 42.50 43.25 35.25 28.50 37.00 39.50 34.50 32.50 31.50 28.50 26.25 23.25 36.75 36.50 36.25 35.25 33.50 Saturday Sunday Index Index Northeast Off-Peak Mass Hub N.Y. Zone-G N.Y. Zone-J N.Y. Zone-A Ontario* PJM Off-Peak PJM West Dominion Hub AD Hub NI Hub MISO Off-Peak Indiana Hub Michigan Hub Minesota Hub Illinios Hub Southeast Off-Peak VACAR Southern, Into Florida TVA, Into Entergy, Into 30.00 30.50 31.25 29.00 22.25 33.00 34.00 31.50 28.00 27.50 27.75 23.00 20.00 32.75 32.50 31.00 31.50 30.00 30.00 30.50 31.25 29.00 22.25 33.00 34.00 31.50 28.00 27.50 27.75 23.00 20.00 32.75 32.50 31.00 31.50 30.00 ERCOT On-peak ERCOT, Houston ERCOT, North ERCOT, South ERCOT, West Saturday Sunday Index Index 30.90 31.00 31.00 30.25 30.90 31.00 31.00 30.25 ERCOT Off-Peak ERCOT, Houston ERCOT, North ERCOT, South ERCOT, West Saturday Sunday Index Index 23.98 24.00 23.75 23.75 23.98 24.00 23.75 23.75

SPP/MRO On-peak MAPP, Soth 31.25 SPP, North 31.00

31.25 31.00

SPP/MRO Off-Peak MAPP, Soth 30.00 SPP, North 29.00

30.00 29.00

Western On-peak COB Mid-C Palo Verde Mead Mona Four Corners NP15 SP15

31.75 29.74 29.75 31.75 30.25 30.00 40.75 49.75

N.A. N.A. N.A. N.A. N.A. N.A. N.A. N.A.

Western Off-Peak COB Mid-C Palo Verde Mead Mona Four Corners NP15 SP15

29.75 28.01 27.05 28.75 26.50 26.75 34.25 37.75

31.85 29.17 27.81 29.50 26.75 27.75 37.00 43.25

*Ontario prices are in Canadian dollars

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w0rld Coal trade Map

New 2013 Edition

A Focus on Coal Imports and Exports

The World Coal Trade, 2013 edition wall map presents the primary components of the dynamic global coal industry. From coal source regions, to flow of coal transportation, to major coal ports and major steels mills, this is an essential reference for all those interested in the global coal trade market.

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Key Features:

· Coalregions--Coloredbyprimarycoaltypeandlabeledwith the coal region name · Coalports · Majorsteelmills(showninChina,theUS,andEurope) · Coaltradeflows · Countries,coloredbycoalconsumption · Countrymapsillustratingcoaltradingpartnersformajor coal exporters · Additionalbar-graphsandinsetmaps · Geographicreferencesandmore.

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