NORTHEAST POWER MARKETS ENERGY WATCH - … Quarterly Q2 2015 - Nat...NORTHEAST POWER MARKETS ENERGY WATCH Authors: Chris Kostas, Paul Flemming and Oliver Kleinbub June 2015 In This

N O R T H E A S T P O W E R M A R K E T S

E N E R G Y W A T C H Authors: Chris Kostas, Paul Flemming and Oliver Kleinbub

June 2015

In This Issue 10-Year Power Price Forecast 2 PJM

6-Month Outlook 60

Basis Spreads: Past, Present & Future

6 New York6-Month Outlook 62

PJM Long-Term Outlook 24 New England

6-Month Outlook 64

New York Long-Term Outlook 38 Natural Gas

10-Year Outlook 66

New England Long-Term Outlook 50 Henry Hub

6-Month Outlook 68

Power & Gas 6-Month Outlook 59

In this quarterly issue of Energy Watch, ESAI presents an in-depth analysis of shale gas production in the Marcellus and Utica regions and the potential outcomes for basis pricing at the various Northeast gas pricing points. The forward curves imply that most basis spreads in the Northeast will be enduring such that winter premiums at pricing points such as Tetco M3, Transco Zone 6 NY and Algonquin City Gate will be enduring over the next ten years. ESAI presents analysis that strongly suggests that there will be convergence in gas basis pricing as long haul pipeline builds increase exports from the region (tightening discounts to Henry Hub) and short haul pipeline builds alleviate bottlenecks within the region. The glide path of convergence is uncertain, however, ESAI presents three potential convergence scenarios.

In the regional sections, ESAI presents power forecasts based on the base case convergence scenario for comparison with the energy forecast based on forward gas prices.

ESAI Power LLC 401 Edgewater Place

Suite 640 Wakefield, MA 01880

T: 781.245.2036 Fax: 781.245.8706

www.esai.com

Note: No parts of the Energy WatchTM may be duplicated, transmitted or stored without ESAI’s written permission. The estimates, forecasts and analyses in this report are our judgment and are subject to change without notice. No warranty is made or implied.

Northeast Energy Watch 6

FOCUS: BASIS SPREADS; PAST, PRESENT & FUTURE Introduction

The North American natural gas market has continued to evolve as shale gas producers have become orders of magnitude more efficient over the past five years. The rapid shift in shale gas production efficiencies has caused regional supply imbalances and significant basis discounts on pipeline systems where production growth has outpaced pipeline take-away capabilities. While it is uncertain if the shifts in regional production will be enduring, it is certain that pipeline take-away capabilities from the newly constrained Marcellus/Utica region will increase rapidly over the coming four years. We believe this increase in pipeline take-away capability will outpace production, decrease summer discounts and help to relieve winter basis premiums in PJM, New York, and New England. Henry Hub prices are likely to remain soft as these new supplies become available to regions south and west of Marcellus/Utica and displace gas once supplied from the Gulf Region.

Background

Between 2002 and 2008 (prior to shale gas development), North American natural gas supplies were primarily sourced from deep conventional wells, with most production coming from the Gulf Coast region. Off-shore Gulf of Mexico production and conventional wells in the Rockies also contributed to U.S. aggregate supplies. Virtually all this supply was sourced from large, deep caverns of natural gas. To produce gas from these types of wells producers simply drilled vertically into large caverns of gas. As the production from these large, easily accessible reservoirs began to decline, however, producers were forced to go further afield for smaller returns, the natural gas supply curve began to steepen, and prices increased.

In 2004, demand began to outstrip production from these larger cheaper gas supply sources and pushed prices above $6.00/MMBtu for a sustained period. Higher natural gas prices between 2006 and 2008 spurred exploration and production from higher cost shale gas plays, like Haynesville and Fayetteville. Producers quickly developed new extraction methods, and reduced production costs by using new hydraulic fracturing fluid combinations, improved 3D seismic imaging, electric powered drilling rigs and directional drilling. These efficiencies reduced the cost of production significantly and began to shift the U.S. supply balance; first from conventional production to shale gas production.

Prior to 2009, nearly all the natural gas consumed in the Northeast originated from the Gulf Region and ran through Henry Hub (the most liquid trading point in North America). As a result of liquidity and transportation paths, Henry Hub has long been the center of North American natural gas market and used as the primary reference point for gas prices throughout the country. Significant production growth in Marcellus over the past five years has recently transformed the significance of Henry Hub, and ESAI believes that this will continue to create pricing imbalances until a long-term supply/demand/transportation equilibrium has been achieved.

© 2015, ESAI Power LLC, Reproduction Prohibited June 2015


Natural Gas Production

Aggregate Production

Figure 1 shows U.S. marketed natural gas over the past 20 years. Between 1995 and 2002, production was relatively stable (at 55 Bcf/day), but began to decline in 2002 as conventional gas well decreased. Then in 2008 gas production began to grow with the development of shale gas, and shale gas production has been growing by leaps and bounds ever since. While shale gas production began originally in the South (in formations like Haynesville and Fayetteville), development moved closer to higher priced demand centers like the Marcellus formation in 2010. The effects of this production growth has been extraordinary, first by reducing Henry Hub prices by displacing gas running north, then by pressuring Northeast gas prices below Henry Hub as pipeline constraints developed against pushing new gas south. Figure 2 shows major natural gas production basins, with Haynesville, Eagle Ford, Utica, and Marcellus standing out as the most significant growth regions.

Figure 1: U.S. Marketed Natural Gas, Total

Figure 2: Shale Gas Production, Major Basins

45

50

55

60

65

70

75

80

1980 1985 1990 1995 2000 2005 2010 2015

Bcf/d

Conventional production decreased despite rising prices

Marcellus shale gas expansion

Shale gas production begins

05

101520253035404550

2007 2008 2009 2010 2011 2012 2013 2014 2015

Bcf/d

Bakken

Niobrara

Permian

Haynesville

Eagle Ford

Utica

Marcellus



Marcellus and Utica Production

The expansion in Marcellus and Utica shale gas production has been extraordinary. Prior to 2010, natural gas production in the region was just 1.0 Bcf/day, with production coming from a few small vertical wells. In 2010, producers began extracting shale gas from the Marcellus formation using horizontal drilling and hydraulic fracturing. Marcellus was chosen for widespread development due to its proximity to large demand centers on the East Coast, high winter premiums, and shallowness. The Utica formation is generally deeper, as it begins in Ohio and slopes below the Marcellus formation in Pennsylvania.

After a slow start in 2010, which required infrastructure build out such as gathering systems and processing plants, Marcellus shale gas production expanded rapidly, and by the end of 2011 production exceeded 4.0 Bcf/day. Figure 3 shows the rapid growth in Marcellus production over the past five years, and the beginning of Utica production growth over the past two years.

Figure 3: Northeast Shale Gas Production

Pennsylvania Production by Region

Marcellus gas has primarily been sourced in Pennsylvania due to a favorable regulatory environment. New York, which also has considerably Marcellus reserves, for example, currently has a moratorium on shale gas production. While shale gas runs below nearly all of Pennsylvania, producers have been focused on the northeast and the southwest regions of Pennsylvania. The northeast region is in close proximity to large demand centers with hither-to-for historically high winter basis premiums (i.e. New York City and eastern PJM), while the southwestern region considerable more natural gas liquids (which increases profit margins). The northeast region is comprised of five counties, though just one (i.e. Susquehanna County) accounts for nearly 40% of production (or 3.6 Bcf/day) of total northeast Pennsylvania production. To put this into perspective, this one county alone has gone from zero production in 2010, to nearly 5% of North American production currently. Southwestern Pennsylvania, which is comprise of just two counties (i.e. Greene and Washington), accounts for about 3.3 Bcf/day (or 4% of U.S. total production). Figure 4

02468

101214161820

2007 2008 2009 2010 2011 2012 2013 2014 2015

Bcf/d

Utica

Marcellus



shows Pennsylvania production (by region) over the past six years, while Figure 5 shows the three most prolific counties. Susquehanna County (in northeast Pennsylvania) is shown with a red line, while Washington and Greene counties are shown in different shades of blue.

Figure 4: Pennsylvania Shale Gas Production, By Region

Figure 5: Pennsylvania Production, Key Counties

Figure 6 shows the five major producing counties in the Northeast. The counties are

color coded for the volume of gas produced at the end of 2014 (the darker colors represent the counties with highest production). Pipelines are also shown on the map. The Tennessee Gas (300L), Transcontinental (Leidy Line) and Dominion pipelines carry the majority of the gas out of the region.

Figure 7 shows the two major producing counties in the Southeast. Washington and Greene Counties produce the majority of the gas in the region. The Columbia and Dominion pipeline systems are the predominant systems in closest proximity to the production.

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

2009 2010 2011 2012 2013 2014 2015

Bcf/d OtherSouthwestNortheast

Source: PA DEP

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

2009 2010 2011 2012 2013 2014 2015

Bcf/dWashington (S-W)Greene (S-W)Susquehanna (N-E)

Source: PA DEP



Figure 6: Northeast Pennsylvania Production Map with Pipelines

Figure 7: Southeast Pennsylvania Production Map with Pipelines



PJM LONG-TERM OUTLOOK PJM ENERGY PRICE & HEAT RATE OUTLOOK

PJM Retirements & New Builds

By the end of the current decade (2011 to 2020), PJM will retire almost 29 GW of capacity that was old, inefficient and unable to economically meet the tighter emissions required by the Mercury and Air Toxics Rule (MATS), the Cross State Air Pollution Rule (CSAPR) and state programs such as New Jersey’s High Energy Demand Day rule (HEDD) which specified tighter NOx restrictions on units typically only run under higher load conditions. Of the 29 GW of retirements in PJM, almost 22 GW is coal-fired capacity. About 90 percent of this coal-fired capacity will have retired by 2015 with 2.5 GW expected beyond 2015 (mostly in 2019 due to the delay of the Dickerson and Chalk Point facilities in PEPCO).

Table 1: PJM Retirements; All Fuel Types

Table 2: PJM Coal-Fired Retirements

The market is responding to the retirement of 29 GW of PJM capacity with 23 GW of

new natural gas-fired capacity, mostly highly efficient CCGTs with typical heat rates of 6,800 Btu/kWh. Some of the units expected in 2017 and 2018 will have heat rates approaching as low as 6,500 Btu/kWh. Figure 1 shows PJM capacity additions through 2018. Additions through 2017 are based on capacity that has cleared in the PJM capacity

Total Deactivated Slated Announced Probable

2011 1,322 1,322 0 0 02012 7,027 7,027 0 0 02013 2,825 2,825 0 0 02014 2,967 2,967 0 0 02015 10,134 9,926 208 0 02016 864 0 479 0 3852017 1,337 0 487 803 472018 761 0 163 0 5982019 1,354 0 1,275 0 792020 135 0 135 0 0Total 28,725 24,066 2,747 803 1,109

Coal Total Deactivated Slated Announced Probable

2011 607 607 0 0 02012 5,948 5,948 0 0 02013 2,564 2,564 0 0 02014 2,290 2,290 0 0 02015 7,867 7,742 125 0 02016 471 0 471 0 02017 163 0 0 163 02018 598 0 0 0 5982019 1,224 0 1,224 0 02020 135 0 135 0 0Total 21,867 19,151 1,955 163 598



auctions while 2018 is based on ESAI’s expectation of 3,500 MW clearing in the upcoming August BRA.

Figure 1: PJM Gas-Fired Capacity Additions

Natural Gas Prices & the Shifting Roles of Gas-Fired Peakers

Prior to 2009, PJM energy prices were largely linked to coal prices. Combined cycle units played a ‘mid-merit’ role, dispatching to meet higher daily loads or operating at higher levels during summer peak periods. Energy prices were influenced by gas mostly during higher load periods. Gas-fired peaking units ran only under very high load conditions or during periods of high generator outages.

As has been well documented in previous issues of Energy Watch, the dramatic shifts to very low natural gas prices in PJM have driven combined cycle economics to levels more competitive than most coal-fired plants. As a result, many combined cycle facilities are operating effectively as base-load, displacing coal plants that are now operating during summer high load conditions and winter conditions with both higher loads and higher gas prices. With a large number of coal plants sidelined for typical daily dispatch, gas-fired peaking capacity is being dispatched to meet daily peaks. Prices during these daily peak hours are very high as peakers typically bid in at prices above pure variable costs to make up for relatively short dispatch times. Although energy clearing prices are higher than coal plant production costs during these peak hours, the number of hours is far too few to dispatch coal plants as they do not have the flexibility to operate to meet daily peaks.

As a result of declining gas prices (and declining coal competitiveness), as well as the higher clearing prices associated with gas-fired peaking capacity, PJM heat rates have been steadily climbing. (PJM on-peak energy prices have remained in the $45/MWh range while gas prices have steadily declined, driving implied market heat rates higher). Due to the high levels of coal plant retirements in 2015, ESAI has long anticipated that gas-fired peaking capacity will experience even greater dispatch in 2015, driving heat rates higher with increasing volatility.

As gas-fired capacity has clearly been playing an increasing role in PJM, it is easy to forget that the total 2015 installed combined cycle capacity is only 24 GW. As this capacity displaces base load coal capacity, it is easier to see the need for the gas-fired capacity to meet

01,0002,0003,0004,0005,0006,0007,0008,000

2011 2012 2013 2014 2015 2016 2017 2018

(MW)



NEW YORK LONG-TERM OUTLOOK NEW YORK ENERGY PRICE & HEAT RATE OUTLOOK

Zone G Energy Price & Heat Rate Outlooks

Delivered natural gas prices in New York have held relatively steady over the past quarter, although we note slightly softer forward quotations beginning in 2018/2019. ESAI’s on-peak power price outlook for Zone G remains steady at $50-51/MWh between 2015 and 2019, as the addition of CPV’s Valley combined-cycle gas turbine (CCGT) in 2018 combines with easing delivered natural gas prices in upstate New York. On-peak power prices are projected to increase beginning in 2020, trending towards $59/MWh by 2024. Off-peak and all-hours power prices at Zone G are expected to follow similar price patterns, as shown in Figure 1 and Table 1.

Figure 1: ESAI Power Price Outlook – Zone G

Figure 2 and Table 2 provide ESAI’s outlook for annual implied market heat rates at

Zone G for on-peak, off-peak and 7x24. Implied market heat rates at Zone G are based on Algonquin City Gate as the underlying natural gas price. On-peak heat rates are projected to increase from 11,156 Btu/kWh in 2016 to 12,862 Btu/kWh in 2023. The increase in the earlier years is largely driven by easing delivered natural gas prices at Algonquin amid stable power prices at NY Zone G. Implied market heat rates are expected to dip slightly in 2018 with the addition of the CPV Valley facility, before continuing to trend gently upwards. As for the current forward market, ESAI’s fundamental heat rate outlook for Zone G on-peak is slightly below the current forward curve in 2016-2017 and largely in line thereafter. ESAI’s off-peak projections for Zone G heat rates are slightly stronger than current forwards in 2016-2018, converging in 2019.

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$80.00 $/MWh

On-Peak 7x24Off-Peak



NEW YORK PRICE IMPACTS OF GAS BASIS CONVERGENCE

Transco Zone 6 NY Gas Price Comparison – ESAI Outlook vs. Futures

As outlined in detail in the front section of this report, the prolific production associated with Marcellus and Utica gas has resulted in widely varying basis prices among the various Northeast pricing points. Transco Zone 6 NY will have winter premiums to Henry Hub, whereas other pricing points such as Millenium, Dominion South and Leidy are less impacted by winter constraints.

Futures trading for delivered gas pricing points such as TZ6-NY are only liquid for 2-3 years at best. Beyond this time frame, broker quotations are simply extended at levels that are often similar to the first couple of years. Forward curves for the New York pricing points are treated similarly to other regions in which prices are extrapolated at currently trade levels and thus do not reflect any market consensus for where prices might transpire relative to expectations for supply and demand or regional gas pipeline development.

Figure 7 below compares the forward basis pricing for TZ6-NY with the ESAI base case convergence outlook for TZ6-NY. Due to pipeline buildouts such as Constitution, ESAI expects that winter premiums will decline starting in the winter of 2017 but summer discounts will only tighten slightly against the forward curve starting in 2018. Modest summer discounts are expected to persist in the longer term.

Figure 8 provides the outright futures prices and a comparison with the outright ESAI fundamental forecast for TZ6-NY. The ESAI outlook includes the basis deltas shown in Figure 7 as well as slight differences in the Henry Hub outlook (ESAI is slightly below the Henry Hub forward curve from 2016 to 2018). Note that the ESAI and futures prices for TZ6-NY are similar in the summer months, but diverge widely in the winter months.

Figure 7: TZ6-NY Basis Comparison – Futures vs. ESAI Base Case

-$2.00

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00TZ6-NY Basis, ESAI Base Case Convergence

TZ6-NY Futures

($/MMBtu)



Figure 8: TZ6-NY Outright Price Comparison – Futures vs. ESAI Base Case

Energy Price Impacts of Futures vs. Basis Convergence

As shown in Figure 7 and Figure 8, forward delivered gas prices in New York, as exemplified by TZ6-NY, are assumed to have the same seasonal premiums and discounts in later years as in the more liquid first two years. ESAI’s analysis indicates that the various gas pricing points should converge over time and that the real unknowns are the glide path to convergence (will prices converge in 2019, 2022 or 2025?) and whether prices will converge with some degree of volatility with changes in supply/demand and the pace of pipeline buildouts.

The following graphics present ESAI’s analysis of the power price impacts of the ESAI gas price convergence relative to the forward curves. Figure 9 shows the impacts of converging regional gas prices (including TZ6-NY & Iroquois Zone 2) on Zone G on and off-peak prices. From 2016 to 2020, the on-peak price impacts are mostly in the range of $1.50-$2.50/MWh. Off-peak impacts are very close to the on-peak impacts. Beyond 2020 the price impacts increase as ESAI’s TZ6-NY basis spreads (as well as other pricing points) move towards convergence while the forward values remain unchanged.

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

TZ6-NY ESAI Base Case Convergence

TZ6-NY Futures

($/MMBtu)



NEW ENGLAND LONG-TERM OUTLOOK NEW ENGLAND ENERGY PRICE & HEAT RATE OUTLOOK

ESAI’s long-term outlook for New England is affected by lower expectations for electricity demand, the overall trajectory of natural gas futures, and to a lesser extent the changes to New England’s generation fleet.

Lower Load Expectations Weigh on New England Heat Rates

On May 1, ISO New England issued the 2015 Capacity, Energy, Loads, and Transmission (CELT) report, which presents a downward revision relative to projections published in 2014. For the first time, the 2015 CELT report addresses the impact of the increasing installation of distributed generation, particularly photovoltaic (PV) solar panels and provides projected amounts PV generation located “behind-the-meter”.

ISO New England’s downward revision of its forecast for New England “gross” load was significantly augmented by increased projections of energy efficiency impacts and the inclusion of estimated “behind-the-meter” PV, resulting in a significantly reduced New England’s residual “net” load over the next 10 years. Figure 1 shows ISO New England’s load projections according to the 2015 CELT and 2014 CELT reports.

Figure 1: New England Annual Energy Projections (GWh)

The current 2015 CELT projections reflect an average reduction in “gross” summer peak

load of 0.5 percent compared to the 2014 CELT. Accounting for increased impacts of energy efficiency programs and “behind-the-meter” PV, ISO New England’s projections for “net” load declined by an average of 1.8 percent. This forecast reduction compares to a 10-year cumulative annual growth rate (CAGR) of 0.5 percent for “net” summer peak load. Similarly, ISO New England’s current projections for annual “gross” energy declined by an average of 0.9 percent compared to the 2014 CELT projections. “Net” annual energy projections after the reduction of energy efficiency and “behind-the-meter PV declined by 2.1 percent on average.

120,000

125,000

130,000

135,000

140,000

145,000

150,000

155,000

160,000 2014 CELT Gross 2015 CELT Gross 2014 CELT Net 2015 CELT Net



PRICE IMPACTS OF ESAI ALGONQUIN OUTLOOK ON MASS HUB

ACG Gas Price Comparison – ESAI Outlook vs. Futures

As outlined in detail in the front section of this report, the prolific production associated with Marcellus and Utica gas has resulted in widely varying basis prices across the various Northeast gas pricing points. Pricing points such as Algonquin City Gate and Iroquois Zone 2 will have winter premiums to Henry Hub, whereas other pricing points such as Dominion South and Leidy are not impacted by winter constraints and have minimal winter pricing impacts.

Because futures trading for delivered gas pricing points is only liquid for 2-3 years at best, broker quotations beyond this time frame are simply extended at levels that are often similar to the first couple of years. The forward curves for Algonquin City Gates are therefore simple extrapolations and do not really reflect any market consensus for where prices might be relative to expectations for supply and demand considerations or gas pipeline development.

Figure 5 below compares the forward basis pricing for Algonquin City Gates with the ESAI base case convergence outlook. Due to implementation of the Algonquin Incremental Market (AIM) project in late 2016, ESAI expects that winter premiums will decline in the winter of 2016/17; however, retirement of the Brayton Point and Mount Tom coal plants in June 2017 will contribute to higher gas demand in the winter of 2017/18 and should drive winter premiums higher. The 670 MW Footprint power gas-fired combined cycle facility is also expected to start in the summer of 2017. Summer discounts are expected to persist as pipeline capacity into New England is unconstrained during the summer months. ESAI expects that winter premiums could be higher than the current forward curve expectations in the winters of 2018/19 and 2019/20.

Figure 6 provides the outright futures prices and a comparison with the outright ESAI fundamental forecast for gas priced at Algonquin City Gates. The ESAI outlook includes the basis deltas shown in Figure 5 as well as slight differences in the Henry Hub outlook (ESAI is slightly below the Henry Hub forward curve from 2016 to 2018). Note that the ESAI and futures prices are similar in the summer months, but diverge in the winter months depending on the year.



Figure 5: Algonquin Basis Comparison – Futures vs. ESAI Base Case

Figure 6: Algonquin Outright Price Comparison – Futures vs. ESAI Base Case

Energy Price Impacts of Futures vs. ESAI Algonquin Outlook

Forward Algonquin gas prices are assumed to have the same seasonal premiums and discounts starting in 2018 and forward. ESAI’s analysis indicates that Algonquin winter basis will decline in 2017 due to the AIM project in late 2016, but the retirement of coal plants and additional gas demand mean that Algonquin winter basis will remain firm into 2020. There

-$2.00

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00ACG Basis, Futures

ACG Basis, ESAI Base Case Convergence

($/MMBtu)

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

ACG Futures

ACG ESAI Base Case Convergence

($/MMBtu)



are currently no viable gas pipeline projects in New England that have a reasonable probability of completion before 2020. After 2020, ESAI assumes that Algonquin winter basis will begin to decline due to a combination of incremental gas pipeline capacity, additional renewable energy and/or potential increases to hydro imports to New England. Over the course of the 10 year time horizon however, ESAI assumes that Algonquin winter basis will drop to about $3.00/MMBtu in 2024 from the expected level of over $8.00/MMBtu in Jan/Feb 2016. This is a base case scenario, but a large pipeline project could collapse winter basis much sooner.

The following graphics present ESAI’s analysis of the power price impacts of the ESAI outlook for Algonquin gas prices relative to the forward values. Figure 7 shows the annual impacts of ESAI’s Algonquin outlook on Mass Hub on and off-peak prices relative to energy prices derived from forward gas prices. The power price impacts generally follow the deltas between the ESAI outlook for winter Algonquin basis and the forwards, especially the lower outlooks for winter basis in 2017. In 2018, ESAI’s Algonquin outlook is largely in line with the forwards and the power price impact is very small.

Although ESAI’s winter basis outlook for 2019 and 2020 is only marginally higher than the forwards, summer prices are also higher. Mass Hub on and off-peak power prices are therefore higher by almost $2.00/MWh.

Figure 7: ESAI Algonquin Outlook Impacts on Mass Hub Energy Prices

Figure 8 provides monthly granularity for the on-peak Mass Hub energy price impacts

due to changing the gas price outlook. The major impact is on the winter months (Jan/Feb) in 2017 and from 2019-2024 when ESAI expects Algonquin winter prices to be lower than forwards. The 2017 winter energy price impact of lower Algonquin prices is between $10 and $15/MWh (Jan/Feb 2017). By winter of 2024, the energy price impacts during Jan/Feb are near $20/MWh.

Summer pricing impacts are near $2.00/MWh lower in 2016 and 2017 but ESAI’s summer Algonquin projections shift higher in 2019, driving summer LMPs higher by $2.00-$2.50/MWh in 2019 and beyond.

-5.00

-4.00

-3.00

-2.00

-1.00

0.00

1.00

2.00

3.00 $/MWh

Mass Hub Off-Peak

Mass Hub On-Peak



POWER & GAS 6-MONTH OUTLOOK

Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15Natural Gas

Henry Hub* $2.77 $2.82 $2.84 $2.85 $2.88 $3.00Tetco-M3 $1.49 $1.48 $1.49 $1.50 $1.56 $2.30Transco Zone 6 Non-NY $2.54 $2.18 $2.12 $1.87 $1.94 $2.76Transco Zone 6 NY $2.48 $2.10 $2.04 $1.78 $1.86 $3.05Algonquin Citygate $1.85 $2.36 $2.34 $2.23 $2.87 $5.64

Fuel Oil#2 Heating Oil, NYH $13.67 $13.54 $14.06 $14.00 $13.80 $13.47#6 Oil 0.3% Sulfur $9.01 $9.20 $9.69 $9.68 $9.29 $9.06#6 Oil 1.0% Sulfur $8.12 $8.24 $8.74 $8.57 $8.10 $8.08

*As of June 19, 2015

Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15PJM

Western Hub ESAI Forecast $40.26 $47.15 $43.34 $39.48 $36.42 $37.25 Forward Market $39.09 $50.10 $46.58 $40.74 $38.93 $39.88

PSEG $33.81 $45.15 $41.34 $38.18 $35.67 $35.25AD Hub $38.61 $42.25 $39.14 $37.08 $34.92 $34.95

New EnglandHub

ESAI Forecast $26.57 $36.81 $35.08 $30.36 $35.32 $56.44 Forward Market $26.29 $38.18 $37.20 $32.43 $37.03 $59.38

NEMA $26.87 $37.81 $35.98 $31.11 $36.42 $57.69CT $27.92 $37.81 $36.08 $30.76 $36.07 $57.24

New YorkZone A

ESAI Forecast $33.82 $40.74 $37.99 $32.31 $33.80 $35.91 Forward Market $33.19 $41.72 $41.00 $35.75 $34.70 $38.10

Zone G ESAI Forecast $31.55 $41.05 $38.35 $32.37 $34.18 $47.98 Forward Market $30.95 $43.01 $41.92 $35.77 $35.70 $49.20

Zone J ESAI Forecast $33.20 $45.18 $42.63 $33.69 $35.17 $49.15 Forward Market $32.59 $46.55 $44.94 $37.30 $36.85 $50.45

Zone K $39.45 $58.93 $61.18 $42.94 $42.22 $52.65

Fuel Price Forward Curves ($/MMBtu)

ESAI Power Price Forecasts ($/MWh)



Six Month Forecast

Commitment of Traders Analysis

There has been little change in the commercial and non-commercial aggregate net position over the past six months. From a historic perspective, the commercial and non-commercial net position has in fact remained very small dating all the way back to August 2014. Figure 2 shows the combined aggregate net position of commercials and non-commercials (as reported by the Commodity Futures Trading Commission, and combining CME and ICE futures and swaps). This indicates both a lack of significant conviction on price direction and a very little ‘perceived’ risk among large traders. Commercials typically use the futures market to offset risk, while speculators (i.e. non-commercials) typically assume that risk believing that prices will move in their direction (so they can lock-in profit). The lack of significant transferal of risk suggests these participants currently believe the forward curve is fairly priced. As a result, our COT outlook is neutral.

Figure 2: Commercial and Non-Commercial Net Positions

Technical Analysis

Our technical analysis is also neutral. After five months of trading sideways, the market now appears stuck in a well-established trading range between $2.50/MMBtu and $3.00/MMBtu. Considering that the cash market has been relatively stable over that same period, there appears little technical evidence to suggest prices will break out of this trading range over the coming weeks. Figure 3 shows the near term continuous contract chart since the beginning of the year. With the exception of a minor winter blip above $3.00/MMBtu prices have remained well entrenched in this trading range.

Figure 4 shows the weekly continuous contract. Although this chart shows a slightly different picture (i.e. a long-term bear market), we are cautious to draw too many conclusions

Month Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15Forecast Price $2.80 $3.15 $3.05 $2.90 $2.80 $2.90

-400,000

-300,000

-200,000

-100,000

0

100,000

200,000

300,000

400,000

May-14 Aug-14 Nov-14 Feb-15 May-15

Non-CommercialsCommercials



from it considering the long nature of the sideways trading range. Weekly momentum is bullish, giving a glimmer of hope to the bulls, but the long-term bear trend remains intact.

Figure 3: Daily Natural Gas Prices (Continuous Contract)

Figure 4: Weekly Natural Gas prices (Continuous Contract)

2015 February March April May June July

2.4

2.5

2.6

2.7

2.8

2.9

3.0

3.1

3.2

3.3

3.4

DailyContinuous

Support

Resistance

Jun Jul Aug Sep Oct Nov Dec 2015 Feb Mar Apr May Jun Jul

2.5

3.0

3.5

4.0

4.5

5.0

WeeklyContinuous

Support

Resistance


Documents

NORTHEAST POWER MARKETS ENERGY WATCH - … Quarterly Q2 2015 - Nat...NORTHEAST POWER MARKETS ENERGY WATCH Authors: Chris Kostas, Paul Flemming and Oliver Kleinbub June 2015 In This