Megawatt Daily by chrisdisles

MEGAWATT DAILY Wednesday, September 14, 2016

Inside this issue

News Headlines

NRG is top bidder for SunEdison projects NRG owns 3,733 MW of renewables SunEdison hurries to sell Buckthorn

(continued on page 2)

MISO's low prices in alert cause 'concern': IMM ELMP system deems no emergency capacity needed Cooling degree days up 23% from summer 2015

(continued on page 3)

Proposed Michigan utility faces roadblocks Utility plans development of gas plants Plant financing could pose risk

(continued on page 4)

ERCOT prices fall despite peakload record Prices rise month on month but fall year over year Usage declines 1.4% year over year

(continued on page 5)

Hot summer fails to boost PJM peakload PJM West price lower than previous summers

FERC approves Tucson Electric coal plant deal FTR values rise on high-priced negative deals Company eyes PURPA enforcement in Connecticut NY crys foul over ISO-NE capacity import proposal

6 6 8 9

Regional day-ahead price changes

Day-ahead peak prices

Regional weather trends

Daily Prior Daily 7-day 14-Sep chg 7-day avg 14-Sep chg forecast ISO Price Locations CAISO NP 15 ERCOT North Hub ISONE Internal Hub MISO Indiana Hub NYISO Zone G PJM West Hub SPP South Hub

34.47 1.26 ▲ 35.32 31.08 1.55 ▲ 27.81 40.23 8.24 ▲ 41.71 38.70 -0.41 ▼ 39.86 38.03 6.05 ▲ 39.71 50.01 11.17 ▲ 41.04 33.19 -7.63 ▼ 32.49

64.4 0.5 ▲ 68.7 81.1 -0.4 ▼ 78.6 74.4 5.2 ▲ 65.9 65.3 -3.8 ▼ 67.5 74.3 3.3 ▲ 67.4 74.7 1.6 ▲ 70.1 71.2 -3.3 ▼ 70.8

Bilateral indexes Into Southern Palo Verde COB Mid-C

31.00 0.75 ▲ 31.89 25.50 1.12 ▲ 25.26 28.64 -2.36 ▼ 31.36 27.79 -1.85 ▼ 28.44

80.7 0.5 ▲ 79.1 67.0 -0.1 ▼ 70.6 64.1 -0.6 ▼ 63.8 64.1 -0.6 ▼ 63.8

Source: Platts

COAL-VS-GAS $/MWH FUEL COST RATIOS 3.0

Virginia transmission outage planned

(continued on page 5)

SPP South ERCOT North Threshold

2.5

Into Southern PJM West MISO Indiana

2.0

Key Drivers/Market Highlights Northeast spot prices higher on weather

1.5

Central spot prices rise despite lower demand

1.0

ERCOT dailies rise with warm weather

0.5

California dailies rise on increasing demand

22-Mar

20-Apr

18-May

16-Jun

15-Jul

12-Aug

12-Sep

The Platts coal-vs-gas fuel cost ratios indicate the regional competitiveness of gas versus coal for power generation. The ratio is calculated by dividing the $/MWh fuel cost for coal by that of gas. Gas generation is cheaper than coal generation when the ratio is greater than one. All price data reflects prompt month fuel contracts. Source: Platts daily OTC coal prices and M2MS gas prices

Platts peak daily demand (GW) Daily change Five day forecast ISO 10-Sep 11-Sep 12-Sep 13-Sep 14-Sep Chg % Chg 15-Sep 16-Sep 17-Sep 18-Sep 19-Sep BPA-Puget 6.17 5.94 6.15 6.68 6.70 0.02 0.30 6.68 6.74 6.32 6.26 6.63 IESO 21.36 18.87 19.98 20.66 19.27 -1.39 -6.73 18.86 19.00 18.27 18.62 19.81 CAISO 33.84 31.26 30.58 30.50 31.33 0.83 2.72 32.32 33.23 31.88 33.68 36.04 ERCOT 49.51 54.99 59.82 51.32 50.63 -0.69 -1.34 50.20 48.08 44.84 43.32 46.79 SPP 36.19 34.26 36.49 32.75 30.53 -2.22 -6.78 31.73 31.07 28.44 28.74 30.26 MISO 84.66 81.84 93.75 93.09 87.26 -5.83 -6.26 88.77 91.47 83.68 83.23 91.11 PJM 129.20 105.14 113.48 113.06 118.01 4.95 4.38 104.24 103.53 101.78 102.83 105.08 NYISO 27.88 23.05 22.36 23.92 24.38 0.46 1.92 21.34 21.92 20.59 20.66 22.87 NEISO 18.78 17.10 16.54 18.94 19.83 0.89 4.70 16.98 17.25 16.54 16.73 18.09 AESO 8.97 9.08 9.34 9.20 9.25 0.05 0.54 9.26 9.32 8.89 8.87 9.35

Season

Season average

Min Max 2016 2015 Chg % Chg 4.91 6.33 5.97 6.69 -0.72 -10.76 18.07 25.09 21.20 19.38 1.82 9.39 24.43 37.47 32.45 33.04 -0.59 -1.79 42.39 63.33 57.03 46.64 10.39 22.28 31.03 44.08 37.71 30.86 6.85 22.20 72.83 114.75 93.84 82.39 11.45 13.90 93.22 143.07 118.75 95.81 22.94 23.94 16.78 29.71 23.63 20.49 3.14 15.32 11.93 23.03 17.12 16.28 0.84 5.16 8.86 9.85 9.27 9.67 -0.40 -4.14

Seasons are defined as: Summer (June – August), Fall (September – November), Winter (December – February), and Spring (March – May). Source: Platts

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ELECTRIC POWER

Megawatt Daily

Wednesday, September 14, 2016

NEWS / PRICING COMMENTARY / Market Fundamentals

News

NRG is top bidder for SunEdison projects NRG Energy expects a bankruptcy court judge to approve on Thursday its purchase of an assortment of renewable projects from SunEdison for $188 million. The purchase and sale agreement, or PSA, is for 2,100 MW of SunEdison’s utility-scale solar and wind assets located in the US, which include 200 MW of construction-ready, fully contracted solar assets in Texas. NRG Energy will take an equity interest in a structured partnership that owns 683 MW of “nearly complete, fully contracted” solar assets in Utah and 1,250 MW of solar and wind assets in various stages of development at locations across the country, including Hawaii. “The PSA provides for total consideration up to $188 million, comprised of an initial payment of $129 million and payment of $15 million upon the execution of designated power purchase agreements for certain assets in development, and up to $44 million in future payments contingent on achieving other development milestones,” NRG said in a statement. SunEdison filed for reorganization under Chapter 11 of the US Bankruptcy Code in the US Bankruptcy court for the Southern District of New York on April 21. The firm retained the financial advisory group Rothschild to help it sell as much as 3,100 MW of operating wind and solar assets located in the US, India, Chile and South Africa, plus a pipeline of roughly 1,000 MW of capacity under construction and another 1,000 MW planned. Several sales have been announced.

Volume 21 / Issue 177 / Wednesday, September 14, 2016 ISSN: 1088-4319

Manager North America Gas and Power Content Rocco Canonica, +1-720-264-6626 Matthew Eversman, +1-713-655-2238 Beth McKay, +1-713-655-2258 Anne Swedberg, +1-720-264-6728 Editors Jeff Ryser, +1-713-658-3225 Mark Watson, +1-713-658-3214 Spot Market Editors Kassia Micek, +1-713-655-2227 Eric Wieser, +1-202-383-2092

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Analysts George McGuirk Jonathan Nelson Director, Global Gas & Power Pricing Mark Callahan Director, Global Gas & Power Content James O’Connell Global Editorial Director, Gas and Power Simon Thorne Chief Content Officer Martin Fraenkel Platts President Imogen Joss

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NRG owns 3,733 MW of renewables In an earlier filing with the court, Craig Cornelius, senior vice president of renewables for NRG Energy, said the company agreed to acquire the equity interests in the SunEdison assets for $144 million in cash, “plus up to an additional $43.8 million in potential earn out payments to SunEdison.” Cornelius said NRG agreed to the “replacement of certain credit-support obligations of SunEdison.” NRG bills itself as “the largest competitive power generation company” in the US, with 50,000 MW of fossil, nuclear, solar, and wind

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SunEdison’s affiliate, the yieldco TerraForm Power, did not enter bankruptcy. However, analysts now say that an auction of SunEdison’s 51% stake in TerraForm Power is looming. On Tuesday, equity analysts at Macquarie Research said they believe an auction of SunEdison’s stake in TerraForm “should begin any day now.” On August 8, SunEdison and a number of its affiliates asked the bankruptcy court to approve a stalking horse agreement with NRG. It asked that an auction be held on an expedited basis. The company was concerned that the value of its businesses could decline if the auction was delayed. NRG’s stalking horse proposal set a floor for the value of the equity interests, and for the past month SunEdison was able to entertain higher bids during a brief go-shop period. However, on September 12, SunEdison confirmed that NRG was the winning bidder in the auction. The deal now must receive approval from the bankruptcy court at a hearing that is scheduled for September 15.

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Megawatt Daily

Wednesday, September 14, 2016

NEWS / PRICING COMMENTARY / Market Fundamentals

generation capacity. It owns 667 net MW of wind generation at 24 wind farms and 585 net MW of solar generation at seven facilities, including a 50.1% stake in the 392 MW Ivanpah concentrating solar thermal facility located in the Mojave Desert in California. Its affiliate, NRG Yield, owns and operates an additional 482 net MW of utility-scale solar generation at ten facilities, and 1,999 net MW at 19 wind farms, including 100% of the 947-MW Alta Wind farm in Tehachapi, California.

MISO AVERAGE REAL TIME LMPS, HENRY HUB SPOT PRICES 35

One of the key assets in NRG’s deal with SunEdison is the 200-MW Buckthorn Solar farm that is ready for construction in Pecos County near Fort Stockton in West Texas. The central Texas town of Georgetown, which decided to rely entirely on renewables for its power, signed a 25-year PPA with the affiliate developing Buckthorn in May 2015. The project, which was expected to be completed by the end of 2017, has been delayed. SunEdison was anxious to expedite the auction process in large part to avoid a default on Buckthorn’s PPA with the City of Georgetown. In an August 9 filing with the court, a Skadden, Arps, Slate, Meagher & Flom attorney for SunEdison said the company “must move with haste to attract other viable bidders before the value of the business declines further. Specifically, the Buckthorn Project faces an April 2017 commercial operation date, which is the date upon which a project is completed and begins production of electricity for sale. “Failure to reach COD by October 25, 2017 would constitute a termination event under the applicable power purchase agreement,” the filing said, “and daily delay damages between the scheduled COD of April 28, 2017 and the final COD of October 25, 2017 are significant.” In order to meet the final COD and obtain construction financing, the Buckthorn Project owner must issue a final notice to proceed “by the end of September 2016 — or, at the latest, early October 2016.” “Should the FNTP not be timely issued and the COD not ultimately reached, it is unlikely that the debtors will be able to monetize the Buckthorn Project and obtain value from that project for their constituents,” the filing said — Jeffrey Ryser

MISO's low prices in alert cause 'concern': IMM Low power prices on a day when the Midcontinent Independent System Operator declared a maximum generation event "caused a little concern" for some stakeholders, the independent market monitor told a key panel Tuesday. During Tuesday's meeting of the Markets Committee of the MISO Board of Directors, David Patton, president of Potomac Economics, MISO's independent market monitor, noted that on July 21, MISO forecast peakload at 125 GW and declared a maximum generation event, which means the entire footprint has a generation shortage. In such an event, known as a Level 2 Energy Emergency Alert, MISO operators can take a sequence of steps, ranging from emergency power purchases from market participants up through deploying interruptible loads and purchasing power from neighboring grid

($/MMBtu)

3.5

3.0

2.5

20 15

Rushing to sell Buckthorn solar farm

($/MWh)

2.0 LMP 2015 (left) LMP 2016 (left) Jan

Feb

Mar

Apr

May

Jun

Jul

Henry Hub 2015 (right) Henry Hub 2016 (right) Aug

Sep

Oct

Nov

Dec

1.5

Source: Midcontinent Independent System Operator

MISO REAL TIME CLEARED PHYSICAL ENERGY 70

(TWh) 2015

2016

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Source: Midcontinent Independent System Operator

operators. However, MISO's peakload forecast was about 4 GW more than actual, as storms in the Great Lakes area reduced temperatures in those areas and market participants voluntarily curtailed load by about 1.6 GW, Patton said. As a result, the maximum real-time energy price that day was about $36/MWh, he said, compared with $192/MWh on July 25, when no such emergency conditions existed. "It caused a little concern among some people that on the hottest day in the year we had low prices," Patton said.

ELMP system deems no emergency capacity needed Emergency pricing rules called for MISO to apply a proxy offer floor price for all emergency power, but they did not set prices, partly because the Extended Locational Marginal Pricing system deemed no emergency capacity was necessary. Therefore, the 195 gas turbines MISO committed were more than necessary, which incurred a revenue sufficiency guarantee uplift charge of more than $1.6 million, Patton said. Formerly known as "convex hull pricing," the ELMP model includes start-up costs in LMPs for fast-start resources and uses offline faststart resources in price formation under scarcity conditions. It was implemented in March 2015. MISO's ELMP software allows fast-start resources that are scheduled at limits or offline to set price, which has resulted in some price increases, but Patton said too few of MISO's online peaking resources are eligible under the ELMP model's protocols. In contrast, the ELMP system's use of offline fast-start resources in price formation has caused price decreases, Patton said, and the net effect over the summer was a price decrease of 1 cent/MWh. Real-time LMPs averaged $30.75/MWh in August compared with

Megawatt Daily

Wednesday, September 14, 2016

NEWS / PRICING COMMENTARY / Market Fundamentals

$29.73/MWh in July and $28.55/MWh in August 2015, according to a written report by Todd Ramey, vice president for system operations and market services. Ramey attributed most of the price strength to increased demand driven by higher temperatures.

Cooling degree days up 23% from summer 2015 Load totaled 65.5 TWh in August, up from 65.4 TWh in July and 62.6 TWh in August 2015, Ramey reported. This June-July-August was hotter than those months in the previous two years and the average of the prior decade, Patton said. Cooling degree days this summer were 23% higher than last summer, Patton said. But another factor in August's higher prices may have been the lack of wind generation, which totaled 2 TWh this August, compared with 2.5 TWh in July and 2.4 TWh in August 2015, according to Ramey's report. Wind supplied 7% of MISO's energy in 2015 up from 6% in 2014, while coal supplied 52%, down from 58% in 2014; natural gas supplied 23%, up from 17% in 2014; and Nuclear supplied 15%, down from 16% in 2014, according to Potomac Economics' latest State of the Market Report for MISO, which was issued in June. Coal prices were flat month to month but lower year over year, according to Ramey's report. Powder River Basin coal averaged $1.36/ MMBtu this July and August, compared with $1.51/MMBtu in August 2015. Spot natural gas prices across the large MISO footprint were mixed. The Chicago City-gate spot price averaged $2.75/MMBtu in August, essentially flat with July's $2.73/MMBtu, but down from August 2015's $2.86/MMBtu. At the Henry Hub, spot natural gas averaged $2.80/ MMBtu this August, compared with $2.79/MMBtu in July and $2.78/ MMBtu in August 2015. â&#x20AC;&#x201D; Mark Watson

Proposed Michigan utility faces roadblocks A proposal by Wisconsin's WEC Energy Group, one of the largest electric utilities in the Midwest, to create a new utility to build and operate natural gas-fired generation in Michigan's Upper Peninsula is running into potential roadblocks. Michigan Attorney General Bill Schuette, in a new filing with the Michigan Public Service Commission, is recommending WEC's application to form the Upper Michigan Energy Resources Corp. (UMERC) be denied. The request is premature because there are "too many unanswered questions about the power supply options" available to WEC and other parties that have not been "adequately analyzed and vetted," Sebastian Coppola, an independent consultant for the Republican attorney general, testified. The PSC staff, too, questioned aspects of the proposal.

Utility plans development of gas plants Foremost is whether the new utility's planned development of 170 MW of gas-fired generation in the UP over the next few years would be sufficient to replace WEC's 431-MW Presque Isle baseload coal plant on the shore of Lake Superior near Marquette.

Assuming timely formation of the new utility, WEC is seeking a final PSC order before the end of 2016, construction on what likely would be two small gas-fired plants in the Upper Penninsula is expected to begin in 2018, with the generation on line in 2019, prior to Presque Isle's closing. The likely gas plant locations have not been made public. The establishment and operation of new generating facilities in the sparsely populated and transmission-challenged region is aimed at resolving long-term reliability concerns related to Presque Isle's planned retirement and would preclude the need for additional and unnecessary transmission costs borne by Michigan ratepayers, according to officials. The attorney general cited the lack of fuel diversity as one of the concerns about UMERC constructing new gas plants as its main source of power supply. "Natural gas prices have been and could potentially be very volatile in the future," Coppola warned. "The potential run-up in gas prices in future years as more power plants convert to natural gas and the current excess supply of natural gas diminishes presents a real risk of escalating power costs." Such a risk is significant, he added, "when the new power plant, which is dependent on natural gas prices, will be the main or only source of power supply to UMERC. It does not appear that UMERC will have a diversified source of power supply after the new power plant begins operations."

Plant financing could pose risk The new utility's ability to finance the new gas plants estimated to cost about $255 million also was called into question. UMERC, Coppola noted, would be a small utility with approximately $84 million of net assets. Yet, it would be asked to finance a project costing a quarter of a billion dollars, or triple its worth. Coppola said he asked if WEC would provide any financial support or guarantees and was told "it is too early to determine the most appropriate methods to finance the project and a number of financing options would be available to UMERC." As a result, Coppola said it appears earlier statements that UMERC would finance the project were "premature or simply a stated desire." He concluded the application should be denied "at this time or until the joint applicants present in a clear and transparent fashion the cost of all available options in order to demonstrate that the recommended course of action is in the best interest of the Michigan Upper Peninsula customers." In a Tuesday interview, WEC spokesman Brian Manthey pointed out Cliffs Natural Resources has agreed to enter into a 20-year power purchase agreement to buy electricity from the new gas plants for its iron ore mines in the Upper Penninsula. The PSC staff said it is unclear if construction of the new gas generation would allow for Presque Isle to be retired without the need for additional infrastructure in order to provide safe, reliable and adequate energy services to the Upper Penninsula. "The proposed new generation is significantly smaller than the existing [Presque Isle] plant and the interconnection locations are not solidified," staff said. WEC's We Energies subsidiary operated Presque Isle under a system support resource (SSR) arrangement with the Midcontinent

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Wednesday, September 14, 2016

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Independent System Operator for two years. That ended when Cliffs, which previously stopped buying power from the utility, switched back to being a We Energies customer. â&#x20AC;&#x201D; Bob Matyi

ERCOT prices fall despite peakload record August demand in the Electric Reliability Council of Texas region set a new peakload record as prices came in as much as 40% below last year with natural gas taking a larger share of the fuel mix. Peakload demand set a new all-time record of 71,093 MW on August 11 and actually broke the 2015 record several times throughout the month. ERCOTâ&#x20AC;&#x2122;s final Seasonal Assessment of Resource Adequacy projected demand to peak this summer at 70,588 MW. Augustâ&#x20AC;&#x2122;s power demand was up 5% from 67,445 MW in July and increased 1.7% from 69,877 MW in August 2015, ERCOT said in its monthly usage report released Friday. Despite increased demand during the month, National Weather Service data shows that Austin, which lies near the center of ERCOT's footprint, had 7.5% less cooling degree-days in August than normal and 6.6% less than from 2015. Natural gas-fired generation increased to 49.1% of the fuel mix in August, the highest itâ&#x20AC;&#x2122;s been since March; thatâ&#x20AC;&#x2122;s up from 45.6% in July but down from 51.2% in August 2015. Houston Ship Channel spot natural gas prices averaged $2.734/MMBtu for August, up from the averaged $2.713/MMBtu average in July, but down from $2.736/MMBtu in August 2015. Coal-fired power inched up to 31% of generatin in August, compared with 30.7% in July and 29.8% in August 2015. Nuclear provided 10.2% of generation, up from 9.7% in July and 10% in August 2015. Wind output in August slipped to 9.4%, down from 13.8% in July but up 8% from last year.

South Hub on-peak averaged $37.60/MWh in August, an increase from $31.42/MWh in July, but down from $59.97 in August 2015. West Hub on-peak prices averaged $35.50/MWh in August, moving up from $30.79/MWh in July but sinking from $58.97/MWh in August 2015. Currently, ERCOT North Hub October packages are valued in the upper $20s/MWh, down from the same time last year, when October 2015 prices averaged in the higher $20s/MWh. October 2015 values averaged $28.50/MWh in September 2015 trading, starting the month around $28.40/MWh, reaching as high as $29.70/MWh and rolling off the curve at $27.45/MWh. Consumers across the grid operator's footprint used 36.46 million MWh in August, down from 36.97 million MWh in August 2015 â&#x20AC;&#x201C; a 1.4% year-on-year decrease, according to the report. Usage fell roughly 4.6% from 38.22 million MWh in July. â&#x20AC;&#x201D; Kassia Micek

Hot summer fails to boost PJM peakload

ERCOT day-ahead locational marginal prices increased month on month but fell year on year. At ERCOT North, the most liquid hub, day-ahead on-peak prices averaged $36/MWh in August, up from $31.86/MWh in July but down from $58.95/MWh the year-ago month. Houston Hub on-peak day-ahead averaged $40.20/MWh in August, up from $35.04/MWh in July, but down from $60.78/MWh in July 2015.

This summer was hotter than the previous three summers in the PJM Interconnection service territory, but systemwide peakload was lower than the highest peakload for those years, and PJM staffers are unsure why. During Tuesday's PJM Operating Committee meeting, Chris Pilong, PJM dispatch manager, presented a written overview of PJM's operations in the period from June through August 2016, which was hotter than the same three-month periods of 2013, 2014 and 2015, judging by the number of cooling degree days at various cities around the PJM footprint. PJM's service territory stretches as far west as Chicago, as far east as New Jersey, as far north as the Pennsylvania shores of Lake Erie and as far south as eastern North Carolina. The National Weather Service reported that this summer's CDD total for Pittsburgh, which lies near the geographic center of the PJM footprint, was about 52% above normal and about 36% above summer 2015 levels. Total load this June through August, at 226.6 TWh, was larger than total loads during the summers of 2013 through 2015, Pilong said. The largest June-through-August total over the previous three years was 216 TWh in the summer of 2013. PJM had 23 hot weather alerts this summer, while the top number of such alerts for the previous three summers was 16 in 2015. Between 10,000 and 13,000 MW of generation was unavailable during this

ERCOT ENERGY BY FUEL TYPE

PJM SUMMER LOADS, 2013 2016

Prices drop year over year

100

(%)

250

200 Water/other Wind Nuclear Coal Natural gas

60 40 20 0

(TWh)

August July June

150 100 50

August 2015

August 2016

Source: Electric Reliability Council of Texas

2013

Source: PJM

2014

2015

2016

Megawatt Daily

Wednesday, September 14, 2016

NEWS / PRICING COMMENTARY / Market Fundamentals

summer's hot weather alerts, Pilong reported. However, the systemwide peakload this summer, 151,293 MW on August 11, was about 4% less than the systemwide peakload in the highest peakload for 2013-2015, which was 157,509 MW on July 18, 2013.

PJM West price lower than previous summers Also, the average day-ahead on-peak locational marginal price at the PJM West Hub was just $36.23/MWh this June through August, compared with $37.83/MWh in that period of 2015, $43.49/MWh in that period of 2014 and $46.53/MWh in that period of 2013, according to the Platts price database. Possible contributors to the lower peakload this summer include behind-the-meter solar power and distributed energy resources, Pilong said. Other possibilities include conservation efforts and more efficient air conditioning, lighting and television.

Virginia transmission outage planned The Operating Committee also learned that a transmission line of about 50 miles in length between Cunningham, Virginia, and Elmont, Virginia, northwest of Richmond, Virginia, would be out of service from October 23 through June 2, 2017 and from September 6, 2017 through December 30, 2017. A rebuilt 500-kV line is slated to go into service by June 1, 2018. The outage is not likely to reduce generation capacity, but it may cause minor thermal overloads and low voltages in the area, stakeholders were told. — Mark Watson

FERC approves Tucson Electric coal plant deal Tucson Electric Power will buy 214 MW in a coal-fired unit in Arizona for $85 million under a deal conditionally approved by the Federal Energy Regulatory Commission. In its Monday order, FERC rejected TEP’s contention that the planned deal wouldn’t harm competition and didn’t raise any horizontal market power concerns (EC16-96). To eliminate the chance that TEP could exercise market power by its growing stake in the 1,755-MW Springerville power plant, FERC ordered the Fortis utility to sell at least 125 MW of capacity and energy during winter peak hours to an entity that lacks a market presence in TEP’s balancing authority area. TEP, which owns about 2,763 MW, pledged to deliver the power to the Palo Verde hub. The requirement will end when the coal-fired San Juan Unit 2 near Farmington, New Mexico, is retired by December 31, 2017. TEP owns 170 MW in the unit. The planned transaction will settle litigation around the Springerville power plant’s 425-MW Unit 1 near Springerville, Arizona. TEP has a 49.5%, or 210 MW, stake in the unit. The rest of the unit is owned by Alterna Springerville LLC and LDVF1 TEP LLC. In 2014, Alterna and LDVF1 filed a complaint about their leases in the Springerville unit at FERC. The commission rejected the complaint and the dispute is pending in the U.S. Court of Appeals for the Ninth Circuit. The suit was put on hold while TEP, Alterna and LDVF1 worked out a settlement agreement.

Even with the increased coal capacity from the planned Springerville transaction, TEP and its sister utility UNS Electric plan to get 30% of their electricity from coal-fired resources by 2030, down from 80% in 2014, according to a mid-July update to the utilities’ integrated resource plan. Their renewable generation is expected to go from 4% to 30% over the same period. TEP is considering exiting the San Juan Unit 1 in July 2022, according to the resource plan. The utility has a 170-MW stake in the unit. The utility could also exit the coal-fired Navajo Generating Station where it owns 168 MW in December 2030, the resource plan update said. Six months later it could exit the Four Corners power plant, where it has a 110-MW stake. — Ethan Howland

FTR values rise on high-priced negative deals Market value for prompt-month financial transmission rights (FTR) obligations in all grid operators’ markets for September 2016 showed a modest increase relative to August amid higher-priced negative contracts. Total contract volume in the September auctions was 165,817 GWh, down 5,896 GWh from August, but up about 5,305 GWh, or 3% from September 2015. Absolute market value of the cleared contracts totaled $86.03 million, a 2% increase from August’s market value, but about 8% below the value of cleared contracts from a year ago,

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according to data from the seven independent system operators. FTRs — also known as congestion revenue rights, transmission congestion contracts, and transmission congestion rights in some markets — are financial instruments that allow market participants to hedge against congestion on the electric grid. An FTR obligation contract entitles the contract owner to either be charged or receive compensation when there is congestion between specific points on the grid in day-ahead electricity markets.

Daily CSAPR allowance assessments, Sep 13 ($/st)

$/st

NOx Annual NOx Seasonal SO2 Group 1 SO2 Group 2

2016 Range

$/st

2017 Range

10.00 5.00-15.00 10.00 5.00-15.00 355.00 325.00-400.00 1250.00 500.00-2000.00 1.75 0.50-3.00 1.75 0.50-3.00 3.50 1.00-6.00 3.50 1.00-6.00

RGGI carbon allowance futures, Sep 12 ($/allowance)

Negative purchased contracts support market

ICE

Average contract values in the September auctions were mostly down month over month across the different contract classes, with negative buy contracts being the only class posting an increase in prices. Volume-weighted average prices for negative buy contracts increased 17 cents, or 38%, month over month. The more expensive contracts helped sustain a higher market value compared to August, but wasn’t enough to boost overall market value above September 2015 levels. Volume-weighted average prices for positive contracts, both buys and sells, were down 21% and 27%, respectively. Negative sell contracts were also down month over month, with volume weighted prices averaging 23 cents, or 27%, lower compared to August. Compared to September 2015, all contract classes recorded similar movements, with negative buy contracts being the only class with premium prices. With FTRs, a positive price means that the contract buyer had to pay the ISO for the contract. A negative price means that buyers are being paid by the ISO to take on the risk of congestion in the opposite direction of the historical prevailing path flow.

Dec16 V15 Dec17 V15 Dec18 V15 Dec16 V16 Dec17 V16 Dec18 V16 Dec16 V17 Dec17 V17 Dec16 V18 Dec17 V18 Dec18 V18 Dec19 V18

Settlement Volume 4.65 4.80 4.98 4.65 4.80 4.98 4.65 4.80 4.65 4.80 4.98 5.18

0 0 0 0 0 0 0 0 0 0 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.

Positive prices rise everywhere except Cal-ISO, NYISO Positive prices cleared mostly at a premium relative to prices in August, with prices coming in lower only in the Cal-ISO and New YorkISO. ERCOT posted the most significant proportional price increase for positive contracts, September prices were nearly 45% higher than August prices. As for the losers, positive prices averaged 39% lower in Cal-ISO and 47% lower in NYISO. For negative contract prices, movements were mixed across the board, with three ISOs posting price increases and four posting lower prices relative to contracts in the August auctions. Like the positive contract class, negative contracts in ERCOT also exhibited the most significant increase month over month with weighted average prices coming in 105% higher relative to August. Elsewhere, MISO and SPP were the other two ISOs with higher negative prices. Coming in with lower prices were Cal-ISO, ISO-NE, NYISO, and PJM.

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Purchased volume down while sold volume up For bought and sold contracts, about 138,033 GWh of contracts were purchased in the September auction while 27,783 GWh of contracts were sold back to the ISOs. ISOs allow market participants to use the monthly auctions to sell off FTRs that they had acquired in previous auctions. Market participants receive funds for positively priced contracts they sell in the auction and must pay to sell off negatively priced FTRs. Purchased contracts in the September auctions were down 9,748

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GWh from August with lower purchased volumes observed in all ISOs with the exception of MISO. In MISO, purchased volumes were mostly unchanged from August, with volumes only rising 1% month over month. For sold contracts, volume came in 3,851 GWh higher relative to August. Higher sold volumes were observed across each ISO included in the Platts survey. Participant rankings for the September auctions show Saracen Energy topping the list with 12,641 GWh of total contracts in the company’s portfolio. In second and third place were DC Energy and EDF Trading with a total respective portfolio volume of 10,366 GWh and 9,910 GWh. For the top three participants, their portfolios were mostly weighted toward positive contract positions with Saracen Energy’s portfolio at 60%, DC Energy’s at 57%, and EDF Trading’s portfolio at 59%. — Jonathan Nelson

Company eyes PURPA enforcement in Connecticut Windham Solar is again bringing its gripes with Connecticut's implementation of a Jimmy Carter-era electricity market policy to FERC, filing its third petition within the past year for enforcement against the state. The latest petition (EL16-115) comes as the Connecticut Public Utilities Regulatory Authority issued a final decision August 24 denying Windham's request for a power purchase agreement for several solar facilities of 1-2 MW in size. The Public Utility Regulatory Policies Act requires utilities to purchase power from small renewable power plants and other qualifying facilities at the full avoided cost of replacing that power with other generation. States are empowered to tailor their own avoided cost rules, providing a limited exception to FERC's exclusive authority over wholesale power sales. Windham in January sought to sell energy and capacity from 26 solar facilities to Eversource, the Connecticut utility where those facilities interconnect. Windham opted to exercise its rights under 18 CFR §292.304(d)(2)(ii), offering a 30-year contract for energy and capacity at the utility's forecasted avoided costs. The facilities at issue are in advanced stages of development and most have garnered approval from the Connecticut Siting Council. Most of the solar units have also already executed interconnection agreements, with Windham having paid Eversource $1.8 million under interconnection agreements to connect the projects, the solar developer told FERC. Eversource, however, refused to purchase the energy and capacity from the QFs, prompting Windham to petition the Connecticut Authority. Under PURPA, FERC has the authority to enforce the statute's requirements on state commissions when requested by generators, and can even take state commissions to federal district court to enforce those requirements. But enforcement actions are rare as the commission generally relies on voluntary compliance or has let the parties themselves engage in the litigation, even when a violation of PURPA was found.

Legally enforceable obligation rebuffed for intermittent resources Windham urged action in this case, asserting that the Connecticut

OUTAGES Generation unit outage report Plant/Operator

Cap Fuel State Status Return Shut

Northeast Beck-2 PGS Darlington-3/OPG Lake Superior/Brookfield Lennox-4/OPG Littlelong/OPG NPIROQFALLS NPKirkland-G1-G5 Pickering-7/OPG Pilgrim/Entergy

103 876 120 525 137 131 117 520 683

h Ont. n Ont. g Ont. g Ont. h Ont. g Ont. g Ont. n Ont. n MA

MO MO PMO MO MO MO MO MO MO

Unk Unk Unk Unk Unk Unk Unk Unk Unk

04/11/16 09/09/16 11/04/14 08/29/16 08/16/16 09/12/16 09/01/16 09/02/16 09/07/16

PJM & MISO Davis-Besse/FirstEnergy North Anna-1/Dominion

1003 903

n OH MO n VA MO

Unk Unk

09/10/16 09/11/16

Southeast & Central Catawba-2/Duke Watts Bar-2/TVA

1180 1164

n SC n TN

Unk Unk

09/10/16 08/31/16

West CsolarIV South/Tenaska Henrietta Solar/SunPower Inland Empire-1/Capine LaRosita-1/Intergen Mesquite Solar-3/Sempra Palo Verde-1/APS Pio Pico-1/Apex Pio Pico-2/Apex Pio Pico-3/Apex Redondo-6/AES Sutter/Calpine Topaz Solar/BHE

130 100 376 180 152 1311 103 103 103 175 525 550

s Calif. PMO s Calif. MO g Calif. PMO g Mex. PMO s Ariz. MO n Ariz. MO g Calif. PMO g Calif. MO g Calif. PMO g Calif. MO g Calif. MO s Calif. MO

Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk Unk

09/13/16 09/08/16 09/13/16 05/30/16 09/08/16 09/07/16 08/18/16 08/05/16 07/22/16 09/13/16 06/06/16 09/13/16

MO MO

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; Solar=s Sources: Generation owners, public information and other market sources.

Authority's decision denying its request for a PPA improperly implied that states and non-regulated utilities should be given deference in regards to the formation of a legally enforceable obligation. "The term 'legally enforceable obligation' is a federal law provision, not a state law provision. As such it must be uniformly interpreted and applied," Windham said. Yet, Connecticut utility regulators "held that intermittent generators are not entitled to a legally enforceable obligation," Windham said, citing language in the final decision that "only QFs that can guarantee a particular quantity of power at a particular time can avail themselves of the option to calculate avoided costs at the time the obligation is incurred." Windham asserted that filing suit with a federal district court "would be particularly appropriate here because the commission has addressed the issue of a state commission prohibiting a QF from a legally enforceable obligation because it is an intermittent resource in JD Wind, [a 2010 FERC order] which eventually ended with the [5th US Circuit Court of Appeals'] clearly erroneous decision in Exelon." That 2014 ruling by a divided panel of the 5th Circuit found that it was within the Texas Public Utilities Commission's discretion to limit legally enforceable obligations to firm power because neither PURPA nor FERC regulations implementing the law addressed the issue (Exelon Wind 1, LLC v. Nelson, 12-51228). The decision created a

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precedent for a state to limit the ability of intermittent resources to sell power under PURPA. The ruling "represents a fundamental misunderstanding of energy contracting," and the "case is a paradigm of what can happen when a court, which is not an expert in the subject matter, decides a case on a basis that no party raised or briefed," Windham said. "Now the Exelon virus has spread to Connecticut, and without firm commission action, it will undoubtedly spread to other states," Windham contended in its plea for FERC to act.

Windham calls for invalidating Connecticut rules According to Windham, the Connecticut Authority also reasoned, in finding that Eversource did not have to buy energy from Windham's QFs, that generators in deregulated states are not entitled to long-term forecasted rates calculated at the time an obligation is incurred, and that "it is unjust and unreasonable [under PURPA] to require a utility to enter into a long-term contract when it has an all-requirements supplier." In ruling that Eversource did not have to purchase capacity from Windham's QFs, the Connecticut Authority found that "because [ISO New England] arranges for capacity requirements and bills Eversource for such requirements, Eversource has no direct need for capacity" and that "costs that Eversource may save from reduced charges from ISONE for capacity are not considered an avoided cost under the commission’s regulations," Windham said. Lastly, the Connecticut Authority held that "it is unjust and

AEP Ohio CBP, November 2016 Auction Deadline is September 23, 2016 AEP Ohio is holding an auction for a full requirements product. The product term is one year, starting June 1, 2017. Bidding starts Monday, November 7, 2016. To participate in the auction, potential suppliers must submit qualification materials by September 23.

— Jasmin Melvin

NY crys foul over ISO-NE capacity proposal An aspect of a proposal to boost liquidity in ISO New England's forward capacity market could annually increase costs for New York power consumers by hundreds of millions of dollars if its implementation is not delayed by a year, warned New York's grid operator, utility regulators, transmission owners and large energy consumers in the state. New York Independent System Operator filed a protest with FERC Friday, challenging ISO-NE's plan to broaden participation by import capacity resources in its forward capacity auction (FCA). The plan is part of ISO-NE's so-called forward capacity market enhancements designed to give market participants more opportunities to secure or shed capacity supply obligations (CSOs) following the region's annual three-year-forward capacity auction. Tariff revisions (ER16-2451) proposed August 19 would also allow new resources to compete to procure a CSO earlier than currently possible and would introduce an option for seasonal bilateral contracting. NYISO said it had no objections to those two elements of the proposal. But the narrow issue of capacity imports that did trigger concern was "critically important" as it could cause "material pricing inefficiencies." But these "potentially severe economic consequences for New York consumers can be avoided if the NYISO is allowed a reasonable time to make needed market rule changes to address capacity exports from constrained capacity areas in the New York Control Area," the grid operator said.

NY seeks one-year implementation delay

Visit our website for more information: www.aepohiocbp.com or email AEP-CBP@nera.com

unreasonable for ratepayers to have to assume the risk of inaccurate forecasting for energy or capacity," Windham's petition to FERC asserted. Windham asked FERC to "enforce PURPA in federal district court in order to invalidate the various Connecticut rules announced in the final decision." The company also asked that the rules be permanently enjoined. FERC, in a notice issued Tuesday, opened Windham's petition for enforcement to public comment through October 3. Per typical procedure, FERC will review the petition and any comments or protests filed, and issue a notice of intent either to act or not to act within 60 days of the petition being filed. A notice of intent not to act would clear the way for Windham to initiate litigation if it so chooses, while a notice of intent to act means that at some point FERC would go to court to enforce PURPA. Windham noted in the petition its right to file suit in federal district court to force the state to properly comply with PURPA.

NYISO called for implementation of the import proposal, with respect to generators in New York only, to be deferred by one capacity year so that it would first apply to capacity commitments beginning June 1, 2018. The City of New York and an unincorporated group of 60 large industrial, commercial and institutional energy consumers with

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manufacturing and other facilities in the state filed comments in support of NYISO's position. They said a postponement or deferral of the implementation of the elements of ISO-NE's proposal at issue would not impact resource commitments made for 2018-19 nor would it detract from the substantive merits of the import proposal. The New York State Public Service Commission also filed comments backing the one-year delay to the effective date of the import proposal as it pertains to capacity exports from New York. "The requested delay would not impede the ability of resources located in other control areas to export capacity to ISO-NE," the PSC said. "It would, however, enable the New York capacity market to avoid a pricing inefficiency that, according to NYISO estimates, would needlessly inflate capacity prices by potentially more than $200 million." ISO-NE holds FCAs each February for CSOs that require power suppliers to be able to deliver capacity for a year-long period three years in the future. This capacity commitment period starts the June 1 three years after the FCA is held and runs through the following May 31. Between the FCA and the start of the capacity commitment period, ISO-NE holds annual CSO bilateral windows, where suppliers can get out of a CSO by selling it to a qualified counterparty at a price agreed upon by the parties, followed several months later by an annual reconfiguration auction, another opportunity to relinquish or compete for CSOs. The aspect of the tariff revisions irking New Yorkers would align market rules applied to import capacity resources with those for generators and demand response resources. Specifically it would allow imports backed by external resources to participate in reconfiguration auctions and CSO bilateral contracting for the second and third early capacity commitment periods, held two years and three years, respectively, after the corresponding FCA. The revised qualification requirements for import capacity resources to participate in the reconfiguration auctions would take effect October 19, under the proposed tariff revisions. NYISO said such an effective date "creates a substantial risk of unjustifiably increasing New York capacity prices and creating inefficient price signals in the NYISO-administered capacity market." David Patton, president of Potomac Economics, NYISO's independent market monitoring unit, explained in an affidavit that NYISO's tariffs and procedures currently do not specify how a generator in NYISO's footprint that has sold capacity to a neighboring

region but would still have capacity available for dispatch to meet some local reliability needs should be treated in NYISO's planning process and capacity market. "By default, the resource will be treated as if it no longer exists, which is inconsistent with operational reality," Patton said.

NYISO market rule changes needed before proposal takes effect NYISO believed it had until June 1, 2018, to address this problem as that is when capacity from the Roseton generating station in southeast New York that cleared ISO-NE's FCA 9 for the 2018-19 planning year was supposed to begin to be exported. Patton contended that "under the current market rules, allowing a generator in a NYISO locality to begin exporting capacity in June 2017 could result in inefficient capacity cost increases in the NYISO’s 2017-18 capability year of as much as $341 million." He explained that the cost increases would be the result of the NYISO's auction clearing as if Roseton no longer existed in the state's load zones G-J. NYISO said it was already in the early stages of formulating a solution to the inefficient outcomes its market rules would produce by not accounting for the continued operation of resources exporting capacity from New York localities. "The issue is extremely complex, however, and an appropriate solution must address a range of issues, which include capacity market design changes, the calculation of capacity market requirements, generator obligations, New York State Reliability Council requirements, NYISO software requirements, and related timing issues," it noted. The grid operator therefore asked FERC to defer implementation of the import proposal for one capacity year for generators in New York localities. NYISO said such relief was "tailored … as narrowly as possible to minimize disruption to ISO-NE's proposed market enhancements." NYISO added that it "would attempt to fashion an immediate market rule change to try to avoid pricing inefficiencies" if its request for deferral of the proposal at issue is denied. A group of New York transmission owners filed a similar protest arguing that FERC must consider the effect of ISO-NE's proposal on neighboring regions when making a determination on the justness and reasonableness of the tariff revisions. — Jasmin Melvin

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FTR market report for Sep 2016 Top 50 participants by volume Participant Total Total Net neg. Net pos. GWh dollars dollars dollars Saracen Energy 12,641.17 5,598,091.59 -2,222,892.97 3,375,198.62 DC Energy 10,366.92 4,364,621.27 -1,875,473.11 2,489,148.16 EDF Trading 9,910.62 4,880,144.96 -2,011,529.00 2,868,615.96 NRG Energy 8,239.27 5,825,625.87 -2,417,664.46 3,407,961.41 Vitol 7,124.24 3,240,001.61 -1,278,877.93 1,961,123.68 MAG Energy Solutions 5,456.27 1,597,926.50 -846,989.02 750,937.48 NextEra Energy 4,940.42 1,212,003.46 -315,347.74 896,655.73 Exelon Generation 4,776.06 5,333,676.91 -2,413,042.52 2,920,634.39 Mercuria Energy America 4,185.61 1,222,722.75 -719,902.62 502,820.13 Parma Energy 3,960.42 737,007.73 -402,722.20 334,285.53 Noble Americas 3,639.40 1,792,904.35 -950,849.64 842,054.71 Velocity American Energy 3,566.18 981,437.91 -150,102.26 831,335.65 Tower Research Capital 3,311.21 1,108,771.97 -512,267.99 596,503.97 Luminant Energy 3,235.26 2,011,725.06 -232,120.52 1,779,604.55 SESCO Enterprises 2,828.29 2,285,652.67 -734,672.99 1,550,979.68 BioUrja Power 2,821.23 1,327,807.13 -687,175.43 640,631.70 Castleton Commodities 2,815.03 1,385,334.12 -883,026.77 502,307.35 Elliott Bay Energy Trading 2,792.68 2,436,780.55 -1,556,927.67 879,852.88 E.ON Global Commodities N. A. 2,640.67 446,079.20 -352,093.62 93,985.58 Monolith Energy 2,636.95 1,427,059.22 -976,064.57 450,994.65 Manatee Transmission 2,575.72 510,880.80 -261,509.39 249,371.42 XO Energy 2,387.58 1,277,427.30 -228,757.06 1,048,670.23 Shell Energy 2,328.26 1,369,715.95 -899,935.76 469,780.19 Great Barrington Energy Fund 2,323.28 1,248,083.11 -314,898.53 933,184.58 LM Power 2,276.76 532,258.08 -59,703.22 472,554.86 PSEG Energy 2,135.57 1,224,278.50 -580,145.83 644,132.68 Hemsworth Capital 2,102.76 765,998.87 -414,203.51 351,795.36 Elmagin Power Fund 1,940.05 501,925.90 -297,485.36 204,440.54 ATNV Energy 1,779.78 1,018,035.78 -675,715.76 342,320.02 GRG Energy 1,679.37 619,830.86 -346,299.32 273,531.54 Direct Energy 1,659.72 1,445,086.19 -331,971.92 1,113,114.27 Freepoint Commodities 1,570.35 1,754,928.31 -34,784.35 1,720,143.96 SIG Energy 1,516.76 1,068,658.91 -434,352.72 634,306.19 Appian Way Energy Partners 1,407.10 1,631,203.69 -357,697.15 1,273,506.55 BTG Pactual 1,349.58 338,776.59 -246,632.67 92,143.92 Uncia Energy 1,330.01 588,817.16 -419,738.90 169,078.26 ELMISO 1,250.76 726,404.78 -503,891.86 222,512.91 Clover Energy 1,057.27 623,434.29 -410,712.52 212,721.77 J Aron 1,022.69 525,584.47 -360,409.42 165,175.05 Divine Power 842.27 145,396.88 -3,017.40 142,379.48 Yuma Electric 824.67 148,815.73 -4,085.52 144,730.21 Black Oak Capital 814.83 489,625.05 -263,022.92 226,602.13 Alegria Fund 793.21 480,856.11 -220,668.17 260,187.94 Z Global 786.59 185,803.20 -185,803.20 0.00 BP Energy 767.94 1,305,798.31 -848,380.42 457,417.89 NYX Energy 758.86 211,917.22 -98,328.84 113,588.38 Blackout Power Trading 739.37 73,728.23 -44,540.69 29,187.54 Citigroup 715.54 1,022,089.01 -261,309.45 760,779.56 Morgan Stanley 711.04 421,869.72 -10,011.64 411,858.08 KFW Energy 683.33 71,165.47 -33,703.54 37,461.93

FTR market report for Sep 2016 RTO activity ranked by volume RTO Total GWh Net neg. GWh Net pos. GWh Participants PJM 62,883.35 -30,293.96 32,589.39 106.00 MISO 38,448.69 -18,260.98 20,187.71 84.00 CAISO 24,689.42 -10,456.47 14,232.95 50.00 ERCOT 14,440.35 -4,381.88 10,058.47 43.00 SPP 9,585.04 -3,299.05 6,285.99 50.00 ISONE 9,287.39 -2,494.25 6,793.13 27.00 NYISO 6,482.88 -2,527.92 3,954.96 31.00 Grand total 165,817.12 -71,714.51 94,102.60 391.00 RTO activity ranked by total dollars RTO Total Net Net neg. Net pos. dollars dollars dollars dollars PJM 33,687,628 2,559,570 -15,564,029 18,123,599 MISO 18,426,260 1,672,545 -8,376,857 10,049,403 ERCOT 10,528,993 2,721,845 -3,903,574 6,625,419 CAISO 9,310,108 1,931,807 -3,689,150 5,620,958 NYISO 7,721,865 1,229,813 -3,246,026 4,475,839 SPP 5,676,633 2,192,230 -1,742,202 3,934,431 ISONE 681,052 456,029 -112,511 568,540 Grand total 86,032,539 12,763,839 -36,634,350 49,398,189

Saracen Energy DC Energy EDF Trading NRG Energy Vitol MAG Energy Solutions NextEra Energy Exelon Generation Mercuria Energy America Parma Energy Noble Americas Velocity American Energy Tower Research Capital Luminant Energy SESCO Enterprises BioUrja Power Castleton Commodities Elliott Bay Energy Trading E.ON Global Commodities N. A. Monolith Energy Manatee Transmission XO Energy Shell Energy Great Barrington Energy Fund LM Power PSEG Energy Hemsworth Capital Elmagin Power Fund ATNV Energy GRG Energy Direct Energy Freepoint Commodities SIG Energy Appian Way Energy Partners BTG Pactual Uncia Energy ELMISO Clover Energy J Aron Divine Power Yuma Electric Black Oak Capital Alegria Fund Z Global BP Energy NYX Energy Blackout Power Trading Citigroup Morgan Stanley KFW Energy -10000

Net neg. GWh Net pos. GWh

-5000

5000

10000

Platts’ compilation, analysis of FTR auctions Platts each month compiles and analyzes data from the seven financial transmission rights auctions held each month by regional transmission organizations. FTRs are a hedging tool to protect market participants from the risk of congestion on the grid between specific points, which is reflected in higher prices. Generally, companies that want to protect themselves against day-ahead congestion costs buy positive or prevailing-flow contracts that pay out if there is congestion. Also sold in auctions are negative or counterflow contracts, for which FTR holders receive a payout in the auction but are required to pay if there is congestion in the day-ahead market. Several ISOs also allow participants to sell back their existing FTR contracts in the auctions. Auction activity can be described in terms of the total volume and price of FTRs cleared in the auction, as well as in terms of positive and negative flow FTRs, and the net volume and value of contracts sold—net positive contracts (positive and zero-priced FTRs purchased by market participants and negative FTRs sold by market participants) minus net negative contracts (negative FTRs purchased by market participants and positive and zero-priced FTRs sold by market participants). The graphs and tables are based on data from the individual RTO auctions and include only trading of FTR obligations for the prompt month. Some RTOs offer multiple time periods during their monthly auctions as well as options contracts, but those types of FTRs are not included in this feature. Some market participants have multiple affiliates which trade FTRs. The data has been consolidated, combining entities from the same parent company, umbrella company or organization. For questions, please contact Jonathan Nelson at (720) 264-6621 (jnelson@spglobal.com) or Matthew Eversman at (713) 655-2238 (matthew.eversman@spglobal.com)

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Wednesday, September 14, 2016

NEWS / PRICING COMMENTARY / Market Fundamentals

FTR market report for Sep 2016 RTO breakout top 10 positive and negative contract paths by total dollars Source Sink Shape CAISO Positive paths MALIN_5_N101 TH_NP15_GEN-APND PALOVRDE_ASR-APND TH_SP15_GEN-APND POD_LAROA2_2_UNITA1-APND TH_SP15_GEN-APND SYLMARDC_2_N501 TH_SP15_GEN-APND MALIN_5_N101 TH_NP15_GEN-APND POD_INTKEP_2_UNITS-APND DAVIS_1_N029 SYLMARDC_2_N501 TH_NP15_GEN-APND TH_ZP26_GEN-APND POD_HELMPG_7_UNIT 1-APND SMDA_ASR-APND TH_NP15_GEN-APND SMDA_ASR-APND MADERAG_7_B2 Negative paths SLAP_SCHD-APND SYLMARDC_2_N501 POD_HELMPG_7_UNIT 3-APND POD_INTKEP_2_UNITS-APND DLAP_SCE-APND SYLMARDC_2_N501 SLAP_SCLD-APND TOPAZC1_7_N021 SLAP_SCHD-APND SYLMARDC_2_N501 POD_COLUSA_2_PL1X3-APND MALIN_5_N101 POD_CHWCHL_1_UNIT-APND POD_INTKEP_2_UNITS-APND SLAP_SCHD-APND MALIN_5_N101 POD_EXCHEC_7_UNIT 1-APND POD_INTKEP_2_UNITS-APND SLAP_SCHD-APND MALIN_5_N101 ERCOT Positive paths HB_NORTH HB_SOUTH HB_NORTH HB_NORTH HB_HOUSTON HB_NORTH HB_HOUSTON HB_SOUTH HB_NORTH HB_WEST Negative paths HB_SOUTH HB_HOUSTON FTR_FTR_G1_4 HB_HOUSTON FTR_FTR_G1_4 CBEC_ALL SD5SES_5 BYU_BYU_34 MNSES_UNIT1 CBEC_ALL ISONE Positive paths .H.INTERNAL_HUB .H.INTERNAL_HUB .H.INTERNAL_HUB .H.INTERNAL_HUB UN.PARIS 34.5GRPW .I.ROSETON 345 1 UN.BERLN_NH13.8BURG .H.INTERNAL_HUB LD.SANDY_PD345 SMDINTLD UN.SEABROOK24.5SBRK Negative paths UN.NORWALK 27.6NOR1 LD.PAWTUCKT13.8 UN.PILGRIM 22.8PILG .I.ROSETON 345 1 UN.SCHILLER115 SCH5 UN.PILGRIM 22.8PILG LD.PAWTUCKT13.8 LD.BATES_ST13.8 LD.PAWTUCKT13.8 LD.PAWTUCKT13.8

Total $

Total MWh

$/MWh

Contracts

Peak Peak Peak Peak Off-peak Peak Peak Peak Peak Peak

148,383 123,471 113,229 108,227 72,946 42,960 41,496 40,657 39,191 38,699

82,448 114,127 102,160 54,114 59,930 15,452 22,000 20,000 133,200 14,400

1.80 9 1.08 5 1.11 2 2.00 5 1.22 5 2.78 2 1.89 2 2.03 3 0.29 2 2.69 2

Peak Off-peak Peak Peak Off-peak Peak Peak Off-peak Off-peak Peak

83,574 63,762 52,111 39,820 38,578 28,162 26,121 26,092 25,342 23,684

43,343 7,444 22,795 30,158 41,150 15,503 5,179 16,858 2,555 12,860

-1.93 4 -8.57 1 -2.29 5 -1.32 4 -0.94 4 -1.82 1 -5.04 2 -1.55 4 -9.92 3 -1.84 3

1,004,116 220,685 726,719 275,184 655,274 1,022,078 570,623 134,899 498,178 843,965 302,101 123,211 178,176 428,155 169,862 119,621 162,182 395,568 115,103 167,765

4.55 9 2.64 34 0.64 64 4.23 12 0.59 79 2.45 7 0.42 63 1.42 29 0.41 48 0.69 103

HB_HOUSTON LZ_SOUTH LZ_NORTH HB_HOUSTON LZ_HOUSTON HB_SOUTH LZ_HOUSTON LZ_SOUTH LZ_NORTH LZ_WEST

Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak

HB_NORTH HB_NORTH HB_NORTH HB_NORTH HB_NORTH HB_HOUSTON HB_NORTH HB_SOUTH HB_NORTH HB_HOUSTON

Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak

517,699 441,612 436,246 229,320 179,091 89,233 65,204 47,701 45,914 45,501

211,142 104,400 84,000 50,400 36,720 57,120 81,077 27,360 123,043 43,200

-2.45 13 -4.23 6 -5.19 5 -4.55 2 -4.88 6 -1.56 4 -0.80 34 -1.74 2 -0.37 23 -1.05 10

.Z.NEMASSBOST .Z.NEMASSBOST .Z.SEMASS .Z.SEMASS LD.N_WODSTK34.5 .H.INTERNAL_HUB .Z.NEWHAMPSHIRE .Z.CONNECTICUT .Z.NEMASSBOST .Z.NEMASSBOST

Peak Off-peak Peak Off-peak Off-peak Peak Off-peak Peak Peak Peak

109,402 71,326 26,285 25,874 21,366 19,759 15,876 14,220 14,091 9,740

198,912 324,211 98,381 145,536 18,048 36,590 19,200 199,080 25,704 16,800

0.55 40 0.22 44 0.27 42 0.18 52 1.18 6 0.54 3 0.83 2 0.07 50 0.55 2 0.58 1

UN.PARIS 34.5GRPW UN.PARIS 34.5GRPW .Z.SEMASS UN.PARIS 34.5GRPW .Z.NEWHAMPSHIRE .Z.SEMASS UN.SHEFIELD34.5SHEF UN.PARIS 34.5GRPW UN.WHITEFLD34.5BETH .Z.SEMASS

Off-peak Off-peak Peak Off-peak Peak Off-peak Peak Off-peak Peak Peak

9,406 5,714 5,522 4,477 4,347 3,648 3,097 2,834 2,643 2,468

7,680 3,840 33,902 4,070 13,440 31,488 4,032 1,920 3,360 10,080

-1.22 1 -1.49 1 -0.16 7 -1.10 2 -0.32 2 -0.12 7 -0.77 2 -1.48 1 -0.79 2 -0.24 1

Megawatt Daily

Wednesday, September 14, 2016

NEWS / PRICING COMMENTARY / Market Fundamentals

FTR market report for Sep 2016 RTO breakout top 10 positive and negative contract paths by total dollars Source Sink Shape MISO Positive paths AMIL.BALDWI51 INDIANA.HUB Peak AMIL.BALDWI52 INDIANA.HUB Peak AMIL.BALDWI53 INDIANA.HUB Peak NIPS.BENTONCO NIPS.NORWAPNOR Peak TVA INDIANA.HUB Peak EAI.CC.PBENRGY ARKANSAS.HUB Peak AMIL.BALDT1.NU AMIL.BGS6 Peak TVA LOUISIANA.HUB Peak ARKANSAS.HUB SME.SME_LOAD Peak SIGE.FOWLR INDIANA.HUB Peak Negative paths EES.BURAS8_CT EES.KAISR4_LD Peak AMMO.SQIN.MVP AMMO.PLMT.MVP Off-peak SIGE.FOWLR AMMO.AUDRN88 Peak AMMO.SQIN.MVP AMMO.PLMT.MVP Peak EES.ENMP_1.AZ EAI.ANO2 Off-peak EES.ENMP_1.AZ EAI.ANO1 Off-peak NIPS.IMPA NIPS.BURROAK.L Peak EAI.MABELV.ARR EAI.ANO1 Off-peak SIGE.FOWLR AMMO.AUDRN88 Off-peak AMMO.SQIN.MVP AMMO.HANN_1.AZ Off-peak NYISO Positive paths NYISO_LBMP_REFERENCE WEST GARDENVILLE___LBMP HUNTLEY___67 N.Y.C. LONGIL NIAGARA____ WEST O.H._GEN_BRUCE WEST NORTHPORT___3 LONGIL KINTIGH____ GENESE WEST GARDENVILLE___LBMP ST LAWRENCE____ NYISO_LBMP_REFERENCE HQ_GEN_IMPORT NYISO_LBMP_REFERENCE Negative paths WEST CENTRL NIAGARA____ KINTIGH____ WEST HUD VL NIAGARA____ O.H._GEN_BRUCE WEST GENESE WEST HISHELDN_WT_PWR CENTRL NINE_MILE_2 RAVENSWOOD___3 HUD VL WEST NORTH N.Y.C. HUD VL PJM Positive paths WESTERN HUB PECO IRONWOOD 4 QUAD C18 KV QC-1 PENELEC IRONWOOD DPL NORTH MTOLIVE 69 KV WRCETRLF PEPCO WORCESTE69 KV LOADT1 Negative paths NEWCHURC13 KV CT1 NEWCHURC13 KV CT1 WESTERN HUB WESTERN HUB WESTERN HUB WESTERN HUB WESTERN HUB WESTERN HUB WESTERN HUB WESTERN HUB

Total $

Total MWh

$/MWh

Contracts

94,752 94,752 94,752 77,138 64,862 64,263 64,061 59,353 49,143 47,143

23,688 4.00 1 23,688 4.00 1 23,688 4.00 1 6,182 12.48 2 35,112 1.85 1 28,762 2.23 1 19,253 3.33 2 25,133 2.36 1 19,622 2.50 1 12,533 3.76 2

69,533 34,186 34,072 33,220 29,771 27,455 26,894 23,678 23,548 23,135

25,133 -2.77 4 2,189 -15.62 1 8,400 -4.06 1 1,478 -22.47 1 6,912 -4.31 1 6,374 -4.31 1 8,904 -3.02 2 6,989 -3.39 1 9,600 -2.45 1 1,920 -12.05 1

Baseload Baseload Baseload Baseload Baseload Baseload Baseload Baseload Baseload Baseload

637,783 239,040 162,435 109,435 95,719 95,465 86,630 83,731 82,987 75,106

132,480 119,520 18,000 20,160 14,400 48,960 54,000 39,600 36,720 63,360

4.81 4 2.00 14 9.02 3 5.43 6 6.65 3 1.95 34 1.60 1 2.11 10 2.26 12 1.19 34

Baseload Baseload Baseload Baseload Baseload Baseload Baseload Baseload Baseload Baseload

1,210,176 492,852 212,522 184,281 73,268 64,404 57,472 56,584 55,491 47,691

275,040 482,400 74,160 151,200 15,120 18,720 102,960 162,720 7,920 43,920

-4.40 11 -1.02 60 -2.87 7 -1.22 27 -4.85 4 -3.44 4 -0.56 6 -0.35 6 -7.01 3 -1.09 5

BGE WESTERN HUB WESTERN HUB N ILLINOIS HUB WESTERN HUB WESTERN HUB DPL SOUTH NEWCHURCH CT1-2 BGE OCEANPIN69 KV OCNPIN

Peak Peak Peak Peak Baseload Off-peak Off-peak Peak Peak Peak

407,466 326,474 173,959 171,091 159,139 155,576 114,019 108,791 98,888 89,375

43,579 9.35 11 67,200 4.86 2 35,246 4.94 4 18,010 9.50 4 71,568 2.22 2 38,400 4.05 4 15,744 7.24 2 1,915 56.80 8 17,472 5.66 5 7,056 12.67 4

INDIANRI26 KV UNIT04 COSTEN 138 KV COSTENSP PSEG PECO PECO PPL PECO METED PPL PECO

Off-peak Peak Off-peak Peak Off-peak Off-peak Peak Peak Peak Off-peak

240,837 202,278 200,650 154,055 120,061 109,415 91,902 82,320 79,380 77,176

4,301 2,990 57,600 33,600 38,400 38,400 18,917 23,520 19,051 20,736

-56.00 -67.64 -3.48 -4.58 -3.13 -2.85 -4.86 -3.50 -4.17 -3.72

4 1 1 1 1 1 5 3 1 3

Megawatt Daily

Wednesday, September 14, 2016

NEWS / PRICING COMMENTARY / Market Fundamentals

FTR market report for Sep 2016 RTO breakout top 10 positive and negative contract paths by total dollars Source Sink Shape SPP Positive paths GRDA_HUB WFEC_WFEC WFEC_HUGO_PLANT WFEC_WFEC WFEC_BALKO_WIND_FARM WFEC_WFEC MIDW.LES.BKEYE WR_MIDW GRDA_HUB WFEC_WFEC SCSE BLKW WFEC_BALKO_WIND_FARM WFEC_WFEC WAUE.BEPM.AVS1 WAUE.BEPM.PGS1 OKGETALOGAWIND OMPA_KNGFISHER NPPD_GGS2 SPRM_SPRM Negative paths AECC_FLTCREEK AECC_CSWS MPSSIBLEYUN3 MPS_MPS MINCOIII GSEC_SPS WR.LAC.1 WR_WR WR.LAC.2 WR_WR MPSSIBLEYUN3 MPS_MPS OKGESNRWIND WR.MW.GMEC.MW SPS.TOLK2 SPS_SPS SPS.TOLK1 SPS_SPS WFEC_WFEC WFEC_OKGE

Total $

Total MWh

$/MWh

Contracts

Peak Off-peak Off-peak Off-peak Off-peak Off-peak Peak Peak Off-peak Off-peak

86,006 64,080 56,761 54,095 46,183 42,490 38,115 31,413 29,149 27,971

36,725 31,258 6,720 19,392 19,315 9,600 7,190 11,693 13,056 9,600

2.34 1 2.05 1 8.45 1 2.79 2 2.39 1 4.43 1 5.30 1 2.69 2 2.23 2 2.91 1

Peak Off-peak Off-peak Off-peak Off-peak Peak Off-peak Off-peak Off-peak Peak

39,795 19,843 19,686 19,576 19,576 17,227 16,988 15,005 14,856 14,154

38,203 -1.04 2 95,462 -0.21 1 16,666 -1.18 1 76,800 -0.25 1 76,800 -0.25 1 66,965 -0.26 2 1,152 -14.75 1 15,398 -0.97 1 15,245 -0.97 1 11,424 -1.24 1

Wednesday, September 14, 2016

Megawatt Daily

NEWS / PRICING COMMENTARY / Market Fundamentals NEWs

Northeast POWER MARKETS Northeast day ahead power prices ($/MWh) Marginal Spark spread Hub/Index Symbol 14-Sep heat rate @7K @12K

Price change Prior 7-day Chg % Chg Average

Month Min

Month Yearly change Max Sep-16 Sep-15 Chg

% Chg

On-Peak ISONE Internal Hub ISONE NE Mass-Boston ISONE Connecticut NYISO Zone G NYISO NYC Zone NYISO West Zone NYISO Capital Zone

IINIM00 40.23 13148 18.81 3.51 8.24 25.8 41.71 17.19 63.50 34.33 36.08 -1.75 -4.9 IINNM00 49.40 16145 27.98 12.68 12.91 35.4 64.07 17.34 85.61 48.09 39.89 8.20 20.6 IINCM00 40.15 13248 18.94 3.78 8.26 25.9 41.63 17.26 62.93 34.33 36.08 -1.75 -4.9 INYHM00 38.03 16192 21.59 9.85 6.05 18.9 39.71 19.94 52.00 33.56 36.96 -3.40 -9.2 INYNM00 41.32 17592 24.88 13.13 6.35 18.2 41.17 20.15 55.57 34.92 38.59 -3.66 -9.5 INYWM00 31.85 17263 18.94 9.71 -14.97 -32.0 41.65 18.04 52.71 34.24 31.44 2.80 8.9 INYCM00 34.43 13841 17.02 4.58 3.64 11.8 36.52 19.53 45.83 31.36 31.07 0.29 0.9

Off-Peak ISONE Internal Hub ISONE NE Mass-Boston ISONE Connecticut NYISO Zone G NYISO NYC Zone NYISO West Zone NYISO Capital Zone

IINIP00 17.11 5349 -5.28 -21.27 IINNP00 17.15 5362 -5.24 -21.23 IINCP00 16.97 5406 -5.00 -20.70 INYHP00 18.50 8134 2.58 -8.79 INYNP00 18.85 8287 2.93 -8.45 INYWP00 17.14 9242 4.16 -5.11 INYCP00 18.04 7180 0.45 -12.11

0.96 5.9 24.26 10.13 30.53 19.91 20.31 -0.40 -2.0 0.99 6.1 26.19 10.17 33.10 20.86 20.84 0.02 0.1 0.94 5.9 24.16 10.12 30.54 19.86 20.18 -0.32 -1.6 0.35 1.9 22.89 12.39 27.67 19.38 19.55 -0.17 -0.9 0.48 2.6 23.35 12.52 28.25 19.77 20.19 -0.42 -2.1 0.22 1.3 19.34 10.01 22.46 16.53 16.82 -0.29 -1.7 0.50 2.9 22.47 12.30 27.92 19.07 18.21 0.86 4.7

NORTHEAST AVG. DAY-AHEAD/REAL-TIME PEAK PRICE SPREAD 40

($/MWh)

20 0 -20 -40 NYISO Zone J -60

31-Aug

NYISO Zone G

02-Sep

NYISO Zone A

04-Sep

06-Sep

NEPOOL Mass Hub

08-Sep

10-Sep

12-Sep

Source: Platts

NORTHEAST PLATTS M2MS FORWARD CURVE: ON-PEAK 100

($/MWh) East NY ZnJ

East NY ZnG

West NY ZnA

Jan-17

Jul-17

Jan-18

Mass Hub

80 60 40 20 Oct-16

Apr-17

Oct-17

Apr-18

Jul-18

Oct-18

Source: Platts

NORTHEAST PLATTS M2MS LOCATIONAL SPREADS: ON-PEAK 40 30

($/MWh) NYISO ZnG/NEPOOL Mass Hub NEPOOL Mass Hub/PJM West

NYISO ZnG/PJM West NYISO ZnJ/NYISO ZnG

NYISO G/NYISO A

20 10 0 -10 -20 Oct-16

Jan-17

Apr-17

Jul-17

Oct-17

Jan-18

Apr-18

Jul-18

Source: Platts

Oct-18

Northeast spot prices higher on weather Northeast spot power prices were mostly up Tuesday, as high temperatures were expected to rise in New York City and Boston. Mass Hub on-peak rose $2.50 to the mid-$30s/MWh for Wednesday delivery on IntercontinentalExchange. Off-peak added 50 cents to about $18.75/MWh. On-peak balance-of-the-week was in the mid-$20s/MWh, with next-week on-peak in the low $30s/MWh. Algonquin Gas Transmission city-gate dropped 15.9 cents to around $3.111/MMBtu for Wednesday delivery on ICE. ISO New England predicted peakload near 19 GW Wednesday. Peakload averaged 18.915 GW for September 5-9, down 1% week on week. New York ISO locational marginal prices were mixed, as warmer weather in New York City was partially offset by cooler conditions in Albany and Rochester. NYISO West Zone A on-peak dropped $15 to $31.75/MWh for Wednesday delivery. New York City Zone J on-peak moved up $6.25 to $41.25/MWh, while Hudson Valley Zone G on-peak gained $6 to roughly $38/MWh. The New York ISO expected peak at 23.7 GW Wednesday. Peakload averaged 26.162 GW for September 5-9, up 1.8% on the week. NYISO Zone G balance-week on-peak was bid at $27.25/MWh and offered at $29/MWh on ICE, with next-week bid at $29.50/MWh and offered at $33/MWh on ICE. Zone A balance-week was bid at $29/MWh, while balance-month was offered at $37/MWh. In the Mid-Atlantic region, PJM West Hub on-peak day-ahead added $9.50 to the mid-$40s/MWh for Wednesday delivery, with off-peak up $3 to roughly $21/MWh on ICE. On-peak balance-week was bid at $33.25/MWh and offered at $33.75/MWh, as next-week was bid at $36.75/MWh and offered at $37.50/MWh. The Mid-Atlantic region of the PJM Interconnection was expected to see peakload around 45.7 GW Wednesday. In the forward power markets, Mass Hub on-peak October was down $1.25 to about $31/MWh on ICE. NYISO Zone A on-peak November declined 75 cents to around $34.25/MWh. Zone G on-peak November mini sank $1 to $34.25/MWh. PJM West Hub on-peak October was up 25 cents to around $34.25/ MWh.

Wednesday, September 14, 2016

Megawatt Daily

NEWS / PRICING COMMENTARY / Market Fundamentals NEWs

PJM/MISO POWER MARKETS PJM/MISO day ahead power prices ($/MWh) Marginal Spark spread Hub/Index Symbol 14-Sep heat rate @7K @12K

Price change Prior 7-day Chg % Chg Average

Month Min

Month Yearly Change Max Sep-16 Sep-15 Chg

% Chg

On-Peak PJM AEP Dayton Hub PJM Dominion Hub PJM Eastern Hub PJM Northern Illinois Hub PJM Western Hub MISO Indiana Hub MISO Minnesota Hub

IPADM00 39.15 16695 22.73 11.01 2.12 5.7 36.75 21.38 49.31 33.23 33.59 -0.36 -1.1 IPDMM00 47.46 15784 26.41 11.38 8.16 20.8 40.14 22.90 53.10 36.25 35.76 0.49 1.4 IPEHM00 49.11 29954 37.63 29.44 12.39 33.7 41.43 15.56 59.61 35.51 38.54 -3.03 -7.9 IPNIM00 34.48 11794 14.02 -0.60 -2.74 -7.4 36.98 21.45 51.40 33.30 32.43 0.87 2.7 IPWHM00 50.01 27789 37.41 28.41 11.17 28.8 41.04 21.64 60.14 36.56 35.52 1.04 2.9 IMIDM00 38.70 20076 25.21 15.57 -0.41 -1.0 39.86 25.10 56.04 36.71 32.09 4.62 14.4 IMINM00 23.76 8583 4.38 -9.46 -0.94 -3.8 24.49 16.69 33.65 23.87 27.67 -3.80 -13.7

Off-Peak PJM AEP Dayton Hub PJM Dominion Hub PJM Eastern Hub PJM Northern Illinois Hub PJM Western Hub MISO Indiana Hub MISO Minnesota Hub

IPADP00 21.02 9916 6.18 -4.42 2.78 15.2 20.27 9.01 21.96 18.02 19.47 -1.45 -7.4 IPDMP00 22.33 7491 1.46 -13.44 2.94 15.2 21.44 9.98 23.10 19.04 20.49 -1.45 -7.1 IPEHP00 24.23 15744 13.46 5.76 7.95 48.8 18.31 5.50 24.23 15.95 18.89 -2.94 -15.6 IPNIP00 20.18 6918 -0.24 -14.82 2.69 15.4 19.67 8.33 21.76 17.32 19.17 -1.85 -9.7 IPWHP00 21.35 11913 8.80 -0.16 3.03 16.5 20.82 8.99 22.81 18.32 19.71 -1.39 -7.1 IMIDP00 21.77 15139 11.70 4.51 -1.12 -4.9 21.21 10.83 24.11 19.10 19.72 -0.62 -3.1 IMINP00 16.85 6063 -2.60 -16.50 2.35 16.2 13.53 6.66 18.95 12.93 15.38 -2.45 -15.9

PJM/MISO AVG. DAY-AHEAD/REAL-TIME PEAK PRICE SPREAD 30

($/MWh)

20 10 0 -10 -20 -30 -40 -50

PJM AD Hub PJM NI Hub PJM West Hub 31-Aug

MISO Minnesota MISO Indiana

02-Sep

04-Sep

06-Sep

08-Sep

10-Sep

12-Sep

Source: Platts

PJM/MISO PLATTS M2MS FORWARD CURVE: ON-PEAK 60

($/MWh)

50 40 30 PJM AEP/Dayton 20 Oct-16

Jan-17

Apr-17

PJM NI Hub Jul-17

Oct-17

MISO Ind. Hub Jan-18

Apr-18

PJM West Jul-18

Oct-18

Source: Platts

PJM/MISO PLATTS M2MS LOCATIONAL SPREADS: ON-PEAK 18

($/MWh) PJM West/MISO Ind. Hub PJM West/PJM AD Hub

PJM West/PJM NI Hub PJM West/NYISO ZnA

6 0 -6 -12 Oct-16

Jan-17

Apr-17

Jul-17

Oct-17

Jan-18

Apr-18

Jul-18

Source: Platts

Oct-18

Central spot prices rise despite lower demand Central spot power prices were stronger Tuesday despite lower demand in the forecast as lower wind generation is expected in the Southwest Power Pool, while spot natural gas prices hovered around $2.90/MMBtu. Indiana Hub on-peak rose almost $2.50 to the high $30s/MWh for Wednesday delivery on IntercontinentalExchange. Off-peak rose $2 to the low $20s/MWh. Balance-of-the-week on-peak was bid at $34.25/ MWh and offered at $36/MWh, with next-week bid at $34.75/MWh and offered at $40/MWh. The Midcontinent ISO projected peakload around 95.2 GW Tuesday and 93.8 GW Wednesday. Peakload averaged 105,588 MW September 5-9, up about 2.5% from the previous week. Highs in Indianapolis are expected to reach 77 degrees Wednesday, down 3 degrees from Tuesday, while highs in Detroit are expected to drop 11 degrees to 71 degrees over the same period. Southwest Power Pool predicted peak demand around 36.9 GW Tuesday and 35.2 GW Wednesday. Peakload averaged 41.8 GW September 5-9, up 5.8% from the previous week. SPP wind generation in the SPP footprint peaked at 9.6 GW Tuesday and was forecast to peak at 3.5 GW Wednesday. AD Hub on-peak gained $4.50 to the high $30s/MWh for Wednesday delivery. On-peak balance-week was bid at $28/MWh and offered at $34/MWh. NI Hub on-peak advanced nearly $4.25 to the high $30s/MWh for Wednesday delivery on ICE. Balance-week on-peak was bid at $28/ MWh. PJM Western region predicted peakload around 62 GW Tuesday and 58.7 GW Wednesday. In the forward power markets, prices were higher as NYMEX October gas futures declined 2 cents to around $2.895/MMBtu. Indiana Hub on-peak October was bid at $39/MWh, as December added 75 cents near $36.25/MWh. AD Hub on-peak November was offered at $34.25/MWh. On-peak December was offered at $38/MWh. NI Hub on-peak October increased more than 25 cents to roughly $31.25/MWh as November rose 25 cents to almost $32/MWh.

Wednesday, September 14, 2016

Megawatt Daily

NEWS / PRICING COMMENTARY / Market Fundamentals NEWs

SOUTHEAST POWER MARKETS Southeast & Central day-ahead power prices ($/MWh) Marginal Spark spread Hub/Index Symbol 14-Sep heat rate @7K @12K

Price change Prior 7-day Chg % Chg Average

Month Min

Month Yearly change Max Sep-16 Sep-15 Chg

% Chg

On-Peak MISO Texas Hub MISO Louisiana SPP North Hub SPP South Hub ERCOT Houston Hub ERCOT North Hub ERCOT South Hub ERCOT West Hub

IMTXM00 37.71 12737 16.99 2.18 2.70 7.7 32.02 27.72 37.71 32.11 30.69 1.42 4.6 IMLAM00 40.05 14155 20.24 6.10 1.30 3.4 35.71 28.10 42.00 34.47 31.14 3.33 10.7 ISNOM00 26.06 9156 6.14 -8.09 7.87 43.3 21.52 13.72 29.17 21.14 22.28 -1.14 -5.1 ISSOM00 33.19 12032 13.88 0.09 -7.63 -18.7 32.49 24.61 40.82 31.51 29.26 2.25 7.7 IERHM00 32.53 10994 11.82 -2.98 -7.44 -18.6 32.14 27.40 39.97 31.22 28.00 3.22 11.5 IERNM00 31.08 10609 10.57 -4.08 1.55 5.2 27.81 24.53 32.32 27.79 27.93 -0.14 -0.5 IERSM00 31.99 10830 11.31 -3.46 -2.20 -6.4 29.95 26.08 34.19 29.46 28.16 1.30 4.6 IERWM00 31.34 11118 11.61 -2.49 0.87 2.9 27.87 23.80 32.31 27.74 27.94 -0.20 -0.7

Off-Peak MISO Texas Hub MISO Louisiana SPP North Hub SPP South Hub ERCOT Houston Hub ERCOT North Hub ERCOT South Hub ERCOT West Hub

IMTXP00 22.26 7489 1.45 -13.41 0.77 3.6 21.84 18.43 23.62 21.64 21.10 0.54 2.6 IMLAP00 22.26 7915 2.57 -11.49 0.33 1.5 22.00 15.86 23.02 20.93 20.82 0.11 0.5 ISNOP00 14.84 5242 -4.98 -19.13 4.75 47.1 9.83 0.40 15.89 10.17 12.39 -2.22 -17.9 ISSOP00 22.11 8071 2.93 -10.76 3.23 17.1 19.60 15.06 24.39 19.71 19.24 0.47 2.4 IERHP00 20.01 6732 -0.80 -15.66 1.72 9.4 18.13 16.84 20.01 18.28 17.92 0.36 2.0 IERNP00 19.91 6836 -0.48 -15.04 2.65 15.4 17.47 15.77 19.91 17.72 17.89 -0.17 -1.0 IERSP00 20.01 6860 -0.41 -14.99 2.21 12.4 17.77 16.54 20.01 17.97 17.97 0.00 0.0 IERWP00 19.93 7187 0.52 -13.35 2.60 15.0 17.50 15.85 19.93 17.73 17.89 -0.16 -0.9

ERCOT dailies rise with warm weather

ERCOT AVG. DAY-AHEAD/REAL-TIME PEAK PRICE SPREAD 30

($/MWh)

0 -30 -60 -90 -120

West Hub Houston Hub North Hub South Hub 31-Aug 02-Sep 04-Sep

-150

06-Sep

08-Sep

10-Sep

12-Sep

Source: Platts

ERCOT PLATTS M2MS FORWARD CURVE: ON-PEAK 80

($/MWh) ERCOT - Houston ERCOT - West ERCOT - North ERCOT - South

70 60 50 40 30 20 Oct-16

Jan-17

Apr-17

Jul-17

Oct-17

Jan-18

Apr-18

Jul-18

Oct-18

Source: Platts

ERCOT PLATTS M2MS LOCATIONAL SPREADS: ON-PEAK 8

($/MWh) North Hub/West Hub North Hub/South Hub Houston Hub/South Hub Houston Hub/North Hub

6 4 2 0 -2 -4 Oct-16

Jan-17

Apr-17

Jul-17

Oct-17

Jan-18

Apr-18

Jul-18

Source: Platts

Oct-18

Electric Reliability Council of Texas dailies were stronger Tuesday morning with temperatures above seasonal norms. ERCOT North Hub day-ahead on-peak advanced nearly $1.50 to the low $30s/MWh for Wednesday delivery on IntercontinentalExchange. Off-peak added $1.25 near $19.50/MWh. Balance-of-the-week on-peak was around $31/MWh. Next-week on-peak was bid at $28.50/MWh and offered at $29.50/MWh. North Hub balance-day on-peak increased 25 cents from morning activity to more than $30.25/MWh, almost 75 cents above where the Tuesday package traded Monday. ERCOT forecast system load to peak around 59.4 GW Tuesday and 59.3 GW Wednesday. ERCOT forecast wind generation to peak around 3,775 MW at 10 pm CDT Wednesday. Real-time prices for Houston Hub and Load Zone spiked to $161.34/ MWh and $158.89/MWh, respectively, at 1:45 pm Tuesday while all other hubs and zones averaged $57.25/MWh and ranged from $27.37/MWh to $92.33/MWh. In the Southeast, dailies were up Tuesday with higher spot gas prices and above-normal temperatures forecast. Into Southern day-ahead on-peak physical power added about 75 cents to the low $30s/MWh for Wednesday delivery on ICE. Spot natural gas at Transco Zone-3 rose 5.2 cents to about $2.940/MMBtu on ICE. Georgia Transmission Corporation day-ahead on-peak was bid at $32/MWh and offered at $33/MWh on ICE. In the Southeast, demand for SOCO was coming in around 31,500 MW around 1 pm CDT, below the forecast of 33,700 MW for that hour, according to EIA's electric system operating data. ERCOT North Hub term prices were moving weaker Tuesday morning as NYMEX October natural gas futures fell 0.6 cent to around $2.909/MMBtu. On ICE, ERCOT North Hub October on-peak futures were down nearly 25 cents to about $27.50/MWh around 10:30 am EDT with heat rates bid at $9.35 MMBtu/MWh and offered at $9.48 MMBtu/MWh. In the Midcontinent Independent System Operator South Region, Arkansas Hub October on-peak was offered at $30/MWh with November steady around $29.25/MWh.

Megawatt Daily

Wednesday, September 14, 2016

NEWS / PRICING COMMENTARY / Market Fundamentals NEWs

WEST POWER MARKETS Western day-ahead power prices ($/MWh) Marginal Spark spread Hub/Index Symbol 14-Sep heat rate @7K @12K

Price change Prior 7-day Chg % Chg Average

Month Min

Month Yearly change Max Sep-16 Sep-15 Chg

% Chg

On-Peak NP15 SP15 ZP26 COB MEAD MID-C Palo Verde

ICNGM00 34.47 10064 10.49 -6.63 1.26 3.8 35.32 30.34 40.07 34.59 37.29 -2.70 -7.2 ICSGM00 33.33 11592 13.20 -1.17 2.81 9.2 32.93 22.87 37.31 31.74 37.50 -5.76 -15.4 ICZGM00 32.93 11452 12.80 -1.58 2.60 8.6 32.89 23.78 37.01 31.58 36.54 -4.96 -13.6 WEABE20 28.64 10138 8.86 -5.26 -2.36 -7.6 31.36 27.75 33.41 30.44 30.90 -0.46 -1.5 AAMBW20 26.25 9130 6.12 -8.25 0.75 2.9 26.71 25.50 30.25 27.30 31.33 -4.03 -12.9 WEABF20 27.79 10179 8.68 -4.97 -1.85 -6.2 28.44 24.53 29.64 27.75 27.00 0.75 2.8 WEACC20 25.50 9003 5.67 -8.49 1.12 4.6 25.26 23.03 28.25 25.83 29.80 -3.97 -13.3

Off-Peak NP15 SP15 ZP26 COB MEAD MID-C Palo Verde

ICNGP00 29.43 8782 5.97 -10.78 0.70 2.4 30.04 27.64 32.02 30.08 29.01 1.07 3.7 ICSGP00 28.67 10085 8.77 -5.44 0.65 2.3 29.11 26.79 31.07 29.15 29.24 -0.09 -0.3 ICZGP00 28.39 9987 8.49 -5.72 0.54 1.9 29.02 26.62 30.95 29.10 28.86 0.24 0.8 WEACJ20 26.50 9381 6.73 -7.40 -0.50 -1.9 26.64 22.00 28.25 25.18 23.33 1.85 7.9 AAMBQ20 23.50 8174 3.38 -11.00 0.25 1.1 23.61 21.50 24.75 22.91 24.67 -1.76 -7.1 WEACL20 26.10 9560 6.99 -6.66 -0.45 -1.7 25.23 20.62 27.11 23.79 23.09 0.70 3.0 WEACT20 21.89 7728 2.06 -12.10 -0.11 -0.5 22.26 20.36 23.25 21.62 23.25 -1.63 -7.0

California dailies rise on increasing demand

CAISO AVG. DAY-AHEAD/REAL-TIME PEAK PRICE SPREAD 20

($/MWh)

10 0 -10 -20 -30 -40 NP15

-50 -60

31-Aug

02-Sep

04-Sep

06-Sep

SP15 08-Sep

ZP26 10-Sep

12-Sep

Source: Platts

WESTERN PLATTS M2MS FORWARD CURVE: ON-PEAK 50

($/MWh)

40 30 20 10 Oct-16

Mid-C SP15 Jan-17

Palo Verde NP15 Apr-17

Jul-17

Oct-17

Jan-18

Apr-18

Jul-18

Oct-18

Source: Platts

WESTERN PLATTS M2MS LOCATIONAL SPREADS: ON-PEAK ($/MWh) 12 10 8 6 4 2 0 -2 -4 -6 Oct-16 Jan-17

SP15/Palo Verde Apr-17

Jul-17

Oct-17

SP15/NP15

Jan-18

Apr-18

SP15/Mid-C Jul-18

Source: Platts

Oct-18

California dailies strengthened Tuesday with higher forecast demand, while Northwest prices fell as forecasts called for mild weather. In California, SP15 day-ahead on-peak added $2 to about $33.25/ MW on IntercontinentalExchange for Wednesday delivery. Off-peak gained 25 cents to around $29/MWh. California ISO projected demand would peak around 30,275 MW Tuesday and 31,350 MW Wednesday. Cal-ISO imports averaged around 180,525 MWh/day September 5-9, according to Platts Megawatt Daily Market Fundamentals Data. On Monday, Cal-ISO imports were around 155,125 MWh/day, down 14% from the previous week. Spot gas prices at PG&E city-gate added 9.8 cents to near $3.423/ MMBtu for Wednesday delivery, while SoCal city-gates moved up 5 cents to about $2.925/MMBtu. The Sacramento high temperature was forecast from around 83 Wednesday, 4 degrees below normal, with lows from around about 51, 6 degrees below normal. In the Southwest, Palo Verde day-ahead on-peak increased $1 to around $25.50/MWh. Off-peak was unchanged at roughly $22/MWh. Spot gas at Kern River, Opal, added 7.3 cents to near $2.788/MMBtu for Wednesday delivery. The high temperature in Phoenix was forecast to be 97 Wednesday, 3 degrees below normal, with the low around 75, near normal. In the Northwest, Mid-Columbia day-ahead on-peak fell $1.75 to about $27.75/MWh for Wednesday delivery. Off-peak eased 50 cents to around $26/MWh. The high temperature in Portland was forecast to be 80 Wednesday, 6 degrees above normal, with the low around 51, 3 degrees below normal. CustomWeather forecasts showed wind speeds in the Northwest dropping Wednesday, which could pull down wind generation. West forward power prices were flat to stronger Tuesday as NYMEX October gas futures fell 0.6 cent to about $2.909/MMBtu. In California, SP15 October on-peak rose 25 cents to about $37.50/ MWh on ICE by 2:30 pm EDT. In the Southwest, Palo Verde October on-peak was flat at about $28.50/MWh. In the Northwest, Mid-Columbia October on-peak was unchanged at about $25.75/MWh

Megawatt Daily

Wednesday, September 14, 2016

NEWS / PRICING COMMENTARY / Market Fundamentals NEWs

Bilaterals Southeast & Central day-ahead bilateral indexes ($/MWh) Marginal Spark spread Hub/Index Symbol 14-Sep heat rate @7K @12K

Price change Prior 7-day Chg % Chg Average

Month Min

Month Yearly change Max Sep-16 Sep-15 Chg

% Chg

On-Peak Florida GTC, Into Southern, Into TVA, Into VACAR

AAMAV20 34.25 11455 13.32 -1.63 -1.25 -3.5 38.93 32.00 43.25 38.03 35.37 2.66 7.5 WAMCJ20 32.00 10684 11.03 -3.94 1.00 3.2 33.50 29.00 37.00 33.22 31.24 1.98 6.3 AAMBJ20 31.00 10351 10.04 -4.94 0.75 2.5 31.89 28.50 34.50 31.81 30.07 1.74 5.8 WEBAB20 33.00 10846 11.70 -3.51 1.25 3.9 35.14 28.75 41.25 34.50 30.57 3.93 12.9 AAMCI20 36.00 11746 14.55 -0.78 4.50 14.3 33.89 28.25 38.25 33.86 32.12 1.74 5.4

Off-Peak Florida GTC, Into Southern, Into TVA, Into VACAR

AAMAO20 26.00 8696 5.07 -9.88 WAMCC20 22.25 7429 1.28 -13.69 AAMBC20 20.75 6928 -0.22 -15.19 AAJER20 21.00 6902 -0.30 -15.51 AAMCB20 21.00 6852 -0.45 -15.78

2.50 10.6 21.61 19.50 26.00 21.05 23.09 -2.04 -8.8 2.50 12.7 18.50 17.00 22.25 18.48 19.88 -1.40 -7.0 2.50 13.7 17.00 15.75 20.75 16.77 19.11 -2.34 -12.2 2.50 13.5 18.14 15.50 21.00 17.38 18.98 -1.60 -8.4 2.75 15.1 17.79 14.50 21.00 16.91 18.76 -1.85 -9.9

Western day-ahead bilateral indexes ($/MWh) Marginal Spark spread Hub/Index Symbol 14-Sep heat rate @7K @12K

Price change Prior 7-day Chg % Chg Average

Month Min

Month Yearly change Max Sep-16 Sep-15 Chg

% Chg

On-Peak Mid-C John Day COB NOB Palo Verde Mona Four Corners Pinnacle Peak Westwing MEAD

WEABF20 27.79 10179 8.68 -4.97 -1.85 -6.2 28.44 24.53 29.64 27.75 27.00 0.75 2.8 WEAHF20 28.75 10531 9.64 -4.01 -2.00 -6.5 29.50 25.50 30.75 28.80 28.00 0.80 2.9 WEABE20 28.64 10138 8.86 -5.26 -2.36 -7.6 31.36 27.75 33.41 30.44 30.90 -0.46 -1.5 WEAIF20 29.25 10714 10.14 -3.51 -1.50 -4.9 30.21 26.75 32.00 29.55 29.26 0.29 1.0 WEACC20 25.50 9003 5.67 -8.49 1.12 4.6 25.26 23.03 28.25 25.83 29.80 -3.97 -13.3 AARLQ20 25.50 9256 6.22 -7.56 -0.25 -1.0 26.21 24.00 29.50 26.66 29.77 -3.11 -10.4 WEABI20 27.50 9857 7.97 -5.98 2.50 10.0 26.11 24.75 28.50 26.66 29.42 -2.76 -9.4 WEAKF20 26.50 9356 6.67 -7.49 1.50 6.0 25.39 22.75 28.50 26.09 30.16 -4.07 -13.5 WEAJF20 25.00 8826 5.17 -8.99 0.25 1.0 25.82 24.50 28.75 26.30 30.28 -3.98 -13.1 AAMBW20 26.25 9130 6.12 -8.25 0.75 2.9 26.71 25.50 30.25 27.30 31.33 -4.03 -12.9

Off-Peak Mid-C John Day COB NOB Palo Verde Mona Four Corners Pinnacle Peak Westwing MEAD

WEACL20 26.10 9560 6.99 -6.66 -0.45 -1.7 25.23 20.62 27.11 23.79 23.09 0.70 3.0 WEAHL20 27.00 9890 7.89 -5.76 -0.50 -1.8 26.18 21.50 28.00 24.73 24.07 0.66 2.7 WEACJ20 26.50 9381 6.73 -7.40 -0.50 -1.9 26.64 22.00 28.25 25.18 23.33 1.85 7.9 WEAIL20 25.50 9341 6.39 -7.26 -1.75 -6.4 26.39 22.50 28.00 25.05 24.37 0.68 2.8 WEACT20 21.89 7728 2.06 -12.10 -0.11 -0.5 22.26 20.36 23.25 21.62 23.25 -1.63 -7.0 AARLO20 21.50 7804 2.22 -11.56 1.50 7.5 20.04 19.00 21.50 20.27 22.65 -2.38 -10.5 WEACR20 22.00 7885 2.47 -11.48 0.00 0.0 22.57 20.00 24.00 21.79 21.99 -0.20 -0.9 WEAKL20 22.25 7855 2.42 -11.74 0.00 0.0 22.04 20.25 23.25 21.43 23.38 -1.95 -8.3 WEAJL20 22.25 7855 2.42 -11.74 0.00 0.0 22.79 20.50 23.75 21.84 23.39 -1.55 -6.6 AAMBQ20 23.50 8174 3.38 -11.00 0.25 1.1 23.61 21.50 24.75 22.91 24.67 -1.76 -7.1

Southeast near-term bilateral markets ($/MWh)

Western near-term bilateral markets ($/MWh)

Package

Trade date

Range

Southern, into Next-week Next-week Next-week

09/13 31.25-31.75 09/08 29.75-30.25 09/07 31.75-32.25

GTC, into Bal-month Next-week

09/12 31.00-31.50 09/08 31.25-31.75

Mid-C Bal-month Bal-month Bal-month Bal-month Bal-month (off-peak)

Trade date

Range

09/13 28.75-30.00 09/12 28.75-29.75 09/08 28.50-29.75 09/07 28.75-29.25 09/08 24.50-25.50

Megawatt Daily

Wednesday, September 14, 2016

NEWS / PRICING COMMENTARY / Market Fundamentals NEWs

Platts M2MS Forward Curve, Sep 13 ($/MWh) Prompt month: Oct 16

On-peak Off-peak

Northeast

On-peak Off-peak

Southeast & Central

Mass Hub N.Y. Zone G N.Y. Zone J N.Y. Zone A Ontario*

31.50 21.70 30.70 20.45 31.90 21.15 35.75 17.55 15.95 9.00

Southern Into ERCOT North ERCOT Houston ERCOT West ERCOT South

*Ontario prices are in Canadian dollars

31.90 27.80 31.90 25.70 28.75

23.60 20.95 21.95 19.30 20.95

Western

PJM & MISO PJM West AD Hub NI Hub Indiana Hub

34.30 33.15 31.60 34.00

Mid-C Palo Verde Mead NP15 SP15

23.55 23.35 20.35 23.70

25.40 22.60 28.70 23.95 30.90 25.45 38.85 31.65 37.25 30.85

ISO Day-Ahead LMP Breakdown for Sep 14 ($/MWh) Avg Marginal Avg Marginal Hub/Zone Average Cong Loss Change $/Mo heat rate Average Cong Loss Change $/Mo heat rate Northeast On-peak ISONE Internal Hub ISONE Connecticut ISONE NE Mass-Boston NYISO Capital Zone NYISO Hudson Valley Zone NYISO N.Y.C. Zone NYISO West Zone

40.23 -1.90 0.16 8.24 34.33 13148 40.15 -1.90 0.08 8.26 34.33 13248 49.40 7.09 0.34 12.91 48.09 16145 34.43 -1.19 2.53 3.64 31.36 13841 38.03 -3.57 3.76 6.05 33.56 16192 41.32 -6.31 4.30 6.35 34.92 17592 31.85 -0.49 0.65 -14.97 34.24 17263

Off-Peak ISONE Internal Hub ISONE Connecticut ISONE NE Mass-Boston NYISO Capital Zone NYISO Hudson Valley Zone NYISO N.Y.C. Zone NYISO West Zone

17.11 0.01 0.05 0.96 19.91 5349 16.97 0.01 -0.09 0.94 19.86 5406 17.15 0.01 0.09 0.99 20.86 5362 18.04 -0.17 1.31 0.50 19.07 7180 18.50 -0.13 1.82 0.35 19.38 8134 18.85 -0.23 2.07 0.48 19.77 8287 17.14 -0.02 0.57 0.22 16.53 9242

39.15 -2.71 -1.77 2.12 33.23 16695 47.46 3.75 0.08 8.16 36.25 15784 49.11 3.12 2.36 12.39 35.51 29954 34.48 -5.59 -3.56 -2.74 33.30 11794 50.01 5.54 0.83 11.17 36.56 27789 38.70 2.60 0.55 -0.41 36.71 20076 23.76 -8.96 -2.84 -0.94 23.87 8583 40.05 3.52 0.98 1.30 34.47 14155 37.71 1.83 0.32 2.70 32.11 12737

Off-Peak PJM AEP-Dayton Hub PJM Dominion Hub PJM Eastern Hub PJM Northern Illinois Hub PJM Western Hub MISO Indiana Hub MISO Minnesota Hub MISO Louisiana Hub MISO Texas Hub

21.02 0.58 0.04 2.78 18.02 9916 22.33 1.90 0.04 2.94 19.04 7491 24.23 3.87 -0.04 7.95 15.95 15744 20.18 0.15 -0.37 2.69 17.32 6918 21.35 0.98 -0.03 3.03 18.32 11913 21.77 0.65 0.51 -1.12 19.10 15139 16.85 -1.21 -2.56 2.35 12.93 6063 22.26 0.89 0.76 0.33 20.93 7915 22.26 0.77 0.88 0.77 21.64 7489

26.06 33.19 32.53 31.08 31.99 31.34

-1.89 3.09 – – – –

-0.86 1.29 – – – –

7.87 -7.63 -7.44 1.55 -2.20 0.87

21.14 31.51 31.22 27.79 29.46 27.74

9156 12032 10994 10609 10830 11118

Off-Peak SPP North Hub SPP South Hub ERCOT Houston Hub ERCOT North Hub ERCOT South Hub ERCOT West Hub

14.84 -2.18 -0.88 4.75 10.17 5242 22.11 3.64 0.57 3.23 19.71 8071 20.01 – – 1.72 18.28 6732 19.91 – – 2.65 17.72 6836 20.01 – – 2.21 17.97 6860 19.93 – – 2.60 17.73 7187

34.47 33.33 32.93

0.00 0.00 0.00

-0.23 -1.37 -1.77

1.26 2.81 2.60

34.59 31.74 31.58

10064 11592 11452

Off-Peak CAISO NP15 Gen Hub CAISO SP15 Gen Hub CAISO ZP26 Gen Hub

29.43 28.67 28.39

PJM & MISO On-peak PJM AEP-Dayton Hub PJM Dominion Hub PJM Eastern Hub PJM Northern Illinois Hub PJM Western Hub MISO Indiana Hub MISO Minnesota Hub MISO Louisiana Hub MISO Texas Hub Southeast & Central On-peak SPP North Hub SPP South Hub ERCOT Houston Hub ERCOT North Hub ERCOT South Hub ERCOT West Hub Western On-peak CAISO NP15 Gen Hub CAISO SP15 Gen Hub CAISO ZP26 Gen Hub

-0.01 0.00 0.00

-0.12 -0.89 -1.17

0.70 0.65 0.54

30.08 29.15 29.10

8782 10085 9987

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