1

State of the Markets Report

2017

April 2018

The Office of Enforcement’s Division of Energy Market Oversight is pleased to 

present the 2017 State of the Markets Report. This report is staff’s annual 

opportunity to share our assessment of natural gas, electric, and other energy 

markets developments during the past year. 
2

In 2017, U.S. natural gas prices rose relative to 2016 prices but remain below 

historical averages. Increased domestic Liquefied Natural Gas (LNG) export 

capacity as well as pipeline deliveries to Mexico contributed to the U.S. becoming

a net natural gas exporter for the first time in 60 years. In southern California, a 

combination of limitations on natural gas storage injections and withdrawals,

outages on Southern California Gas (SoCal Gas) pipelines, and cold weather

events resulted in all-time record high natural gas prices.

Consistent with higher natural gas prices, wholesale power prices also increased in 

2017 relative to 2016. Wind, solar, and natural gas-fired generation capacity 

increased nationwide, as did electric storage capacity, led by the growth of 

batteries. The California ISO (CAISO) and ISO New England experienced a net 

reduction in generation capacity while the Midcontinent ISO (MISO), the 

Southwest Power Pool (SPP), and PJM Interconnection (PJM) added both 

generation capacity and new transmission lines.
3

Average U.S. natural gas spot prices rose 21% in 2017 from 2016, with the Henry 

Hub averaging $2.96/MMBtu, up from $2.48/MMBtu in 2016. Prices at the 

Henry Hub remain 7% below the average of the previous 5 years and 33% below 

the average of the previous 10 years. Cold weather and high winter heating load at 

both the beginning and the end of 2017 contributed to a 28% increase in average 

natural gas spot prices in the East, relative to 2016. Natural gas prices reached

$34/MMBtu in Boston in December of 2017. The Boston area price did not 

exceed $13/MMBtu in 2016. 

Natural gas prices in the Marcellus Shale region rose 19% in 2017, to an average 

of $2.79/MMBtu. New pipeline capacity allowed producers in the region to meet

a larger share of demand in previously inaccessible market areas, resulting in

rising prices in the Marcellus region. Finally, pipeline and storage limitations in 

southern California continued to constrain the Los Angeles market area, where 

average prices rose 18% to $2.85/MMBtu.

At the end of 2017 continuing through early 2018, natural gas and power markets 

experienced extremely frigid weather that pushed average temperatures across the 

U.S. below levels seen during the 2014 Polar Vortex. As a result, natural gas and 

power prices across the country spiked in early 2018 to historically high levels. 

Staff will discuss this event in more detail later in the report.
4

Nearly 12 Billion Cubic Feet per day (Bcfd) and 773 miles of Commissionjurisdictional natural gas pipeline capacity went into service in 2017. Many of the 

new projects connect Marcellus and Utica shale natural gas fields to markets in the 

Northeast and Midwest. Some of the largest projects increased natural gas 

transportation capacity moving natural gas towards the Gulf Coast. Columbia’s 

1.5 Bcfd Leach Xpress, which commenced service December 28, 2017, transports 

natural gas from West Virginia and Pennsylvania to Kentucky, where existing 

pipeline infrastructure provides transportation into Louisiana. Several other new 

pipeline projects supply LNG export locations. For example, three separate 

pipeline projects, with a combined 2.1 Bcfd of capacity, supply the existing Sabine 

Pass LNG liquefaction facility as well as new LNG export facilities at Cove Point 

and Elba Island. Several new U.S./Mexico border-crossing pipelines in Texas also 

added 3.5 Bcfd of export capacity. 

An expansion at Perryville Gas Storage was the only storage facility placed into 

service in 2017, adding 600 MMcfd of withdrawal capacity in Louisiana. Two 

LNG liquefaction trains achieved commercial start-up in 2017, representing nearly 

1.5 Bcfd of deliverability capacity in the same region.

Finally, in 2017 the Commission certificated 49 pipeline projects encompassing 

30.8 Bcfd of capacity and 2,739 miles of pipeline. These projects include Nexus 

Gas Transmission, Mountaineer Xpress, and Rover Pipeline, which at 3.25 Bcfd is 

the largest single pipeline ever certificated by FERC. Additionally, one storage 

facility in Ohio with 10 MMcfd of withdrawal capacity was certificated.
5

U.S. natural gas production rose 1.0% in 2017, averaging 73.6 Bcfd. In 2017, the 

production decline seen during 2016 was reversed. Production remained mostly 

flat in the first half of 2017 due to low prices resulting from a mild 2016-2017 

winter and high storage levels. However, natural gas production strongly 

rebounded in the second half of the year. Improvements in drilling efficiencies 

allowed producers to expand operations, even as prices at major producing regions 

remained stable. In December 2017, U.S. natural gas production reached an 

average monthly record of 78.3 Bcfd. The contribution of shale natural gas to 

total U.S. natural gas production also increased in 2017, reaching 62.4% compared 

to only 9.9% a decade earlier. Conventional natural gas production provided

37.2% of total dry natural gas production in 2017 compared to 81.7% in 2009.

New pipeline capacity out of the Marcellus and Utica shale plays allowed 

producers to meet demand in previously inaccessible markets. These shale plays 

demonstrated the largest U.S. natural gas production growth in 2017, with a 10.3% 

year-over-year increase for a total production of 22.1 Bcfd by the end of 2017. 

Natural gas production from the Permian Basin of West Texas rose 26.4%, 

averaging almost 5 Bcfd. Most Permian Basin natural gas is produced in 

association with crude oil. With crude oil prices averaging $50.80/Barrel

throughout 2017, companies operating in the Permian Basin were able to 

profitably expand natural gas production despite relatively low natural gas prices 
6

and constrained transportation capacity. Natural gas production from the Permian

Basin reached a monthly record in December 2017, averaging 5.6 Bcfd.
7

Total U.S. natural gas demand averaged 74.5 Bcfd in 2017, down slightly from

2016 demand levels. Natural gas used for power generation, also known as power 

burn, fell 6% from 2016 to 25.3 Bcfd as Cooling Degree Days in 2017 fell 3.5% 

from 2016 requiring less power generation for cooling load. The largest increase 

in demand for natural gas came from LNG exports, which rose from .63 Bcfd to 

2.19 Bcfd, a 248% increase. Meanwhile, industrial natural gas demand rose 1% to 

21.2 Bcfd, while residential/commercial natural gas demand remained flat at 25.3 

Bcfd. Average monthly U.S. natural gas demand for 2017 peaked in December at 

95 Bcfd.

Regionally, demand for natural gas fell in the Northeast and Southwest regions 

and in Texas as a nearly 10% decline in power burn in those markets led to a 1.2 

Bcfd cumulative decline in demand. In the Southeast region, LNG exports buoyed 

natural gas demand as declines in power burn and residential/commercial demand 

were outpaced by a 1.5 Bcfd increase in LNG exports. 
8

The U.S. became a net exporter of natural gas for the first time since 1958, as 

increasing shipments of LNG to world markets and natural gas pipeline deliveries 

to Mexico exceeded imports from Canada and other countries. 

LNG exports more than tripled from 2016, making LNG the fastest-growing 

demand sector in 2017, as two additional trains at Cheniere’s Sabine Pass LNG in 

Louisiana came online. Construction is currently underway at four other terminals 

on the Gulf Coast and Atlantic Seaboard, as well as a one-train expansion at 

Sabine Pass, with most of that capacity expected to be online by 2020.

Natural gas trade with Mexico also grew in 2017, as both LNG and pipeline 

shipments from the U.S. to Mexico increased. Mexico was the most common 

destination for U.S.-sourced LNG shipments, with 40 cargoes totaling nearly 137 

Bcf delivered to its regasification terminals. Pipeline exports to Mexico have 

steadily increased since 2010 and total exports to Mexico increased by about 0.5 

Bcfd from 2016, topping 4.2 Bcfd on average in 2017 and setting a new single-day 

high of 4.5 Bcfd in August. Cross-border flows were spurred by the opening of 

Energy Transfer Partners’ Comanche Trail and Trans-Pecos pipelines in January 

and March of 2017, which collectively added 2.4 Bcfd of capacity in west Texas.
9

In 2017, the third lowest weekly storage injection rate was recorded since 2010, as 

natural gas demand outpaced natural gas supply by nearly 500 Bcf. Average 

Heating Degree Days in December 2017/January 2018 were 14% larger than 

December 2016/January 2017 and 2% larger than the 5 year average for 

December/January. Cold temperatures in late December 2017 and early January

2018 led to the largest storage withdrawal in history of 359 Bcf for the week 

ending on January 5, 2018. It surpassed the previous 2014 record withdrawal of 

288 Bcf by nearly 25%. Large winter withdrawals helped push storage inventories 

to 1.35 Trillion Cubic Feet on April 5, 2018, the lowest end-of-winter storage 

figure since 2014. 
10

Platts publishes a daily and monthly survey of weighted-average natural gas 

prices, volumes and numbers of transactions at various locations across the U.S. 

and Canada. Since Platts began publishing prices, next-day and next-month 

natural gas volumes peaked in 2008. After peaking, volumes declined by 51% and 

70%, respectively, through October 2017. In October 2017, Platts and the 

Intercontinental Exchange (ICE), the leading exchange for physical natural gas 

transactions, implemented their agreement to incorporate ICE price data into 

Platts’ indices to increase published volumes. Platts entered into this agreement to 

improve the transparency and bolster the liquidity of their natural gas indices. 

Since implementation of the agreement, Platts’ published natural gas volumes in 

the next-day market have more than doubled, while next-month volumes have 

more than tripled, meaning that more natural gas volume is contributing to the 

price formation of its published indices. 
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Staff analysis of total physical natural gas purchases and sales shows that 

transactions that reference natural gas indices remain the predominant way market 

participants physically buy or sell natural gas. The Commission collects 

aggregated physical natural gas transactional information from market participants 

through the FERC Form No. 552. The data for calendar year 2017 is due on May 

1, but according to the 2016 data, the volume of transactions that settled off of 

next-day and next-month indices totaled 78% of total physical sales and purchases. 

In contrast, the fixed-price next-day, fixed-price next-month and physical basis 

volumes that helped create those indices represented only 21% of total physical 

sales plus purchases. 
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In October 2015, a large natural gas leak was discovered at the Aliso Canyon 

storage facility, the largest storage field in southern California. Upon discovery of 

the leak, the facility’s storage capacity was reduced from 86 Bcf to 15 Bcf and no 

further injections were allowed at the facility until all of its wells were inspected. 

After the inspection was complete, state agencies approved limited withdrawals 

from Aliso Canyon during extreme weather events. In January 2017, Aliso 

Canyon saw two storage withdrawals when southern California temperatures fell 

below 40 degrees. There were no withdrawals from Aliso Canyon after January 

through the remainder of 2017. In July of 2017, Aliso Canyon was approved to 

begin injecting into storage on a limited basis. The California Public Utility 

Commission (CPUC) then ordered that working natural gas inventories be brought 

up to 23.6 Bcf, 8.6 Bcf higher than when the natural gas leaks were discovered. 

State agencies allowed limited withdrawals to ensure reliability, terming it an 

“asset of last resort.” 

Already affected by the limited operation of Aliso Canyon storage facility, outages 

on SoCal Gas’s pipeline system further reduced capacity to serve natural gas 

demand in the region. The outages limited the access of the northern part of the 

system to two, rather than three, interstate pipelines. On October 2, 2017, 

SoCalGas’ Line 235 ruptured, forcing additional pipeline segments out of service 

and reducing the amount SoCalGas could flow by about 800 MMcfd. With other 

pipelines and storage facilities already out of service for maintenance, the CPUC

issued a warning that power generators could see curtailments in the winter. 

Despite the warning, no curtailments occurred in 2017. According to the CPUC, 
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natural gas supply dropped to 3.3 Bcfd in December 2017 from 4.6 Bcfd the 

previous year. 
14

For most of 2017, southern California next-day natural gas prices measured at the 

SoCal Citygate remained within their five-year range. However, pipeline issues 

along the SoCalGas system combined with colder than normal weather led prices 

to increase late in the year. From September 1 through December 31, next-day 

natural gas prices at SoCal Citygate averaged $3.88/MMBtu, approximately 99 

cents higher than the Henry Hub. By comparison, prices averaged only 3 cents 

higher than the Henry Hub over the same time period in 2016, and 22 cents higher 

during that timeframe from 2009 through 2016. SoCal Citygate prices were 

higher than the five-year range for 32 days last year, peaking at an all-time record 

of $11.83/MMBtu on October 24.

Supply conditions drove power prices downward in southern California in the first 

half of 2017. Hydro generation from the state’s ample water conditions and

growing renewable generation led to more than sufficient generation in the spring, 

when load is low, resulting in lower—and at times negative—prices. 

In the summer, several heat events led to high loads, which topped resource 

adequacy requirements and almost set a new demand record. On September 1st,

load exceeded 50,000 MW, just shy of the all-time demand record of 50,270 MW

set in 2006. If not for California’s almost 6,000 MW of behind-the-meter-solar 

generation, CAISO would have exceeded the 2006 load record. In addition to 

tight supply and demand conditions, growing renewable generation added to 

forecasting, supply, and demand uncertainty. Finally, power prices rose modestly 

late in the year as the natural gas issues discussed earlier elevated natural gas 
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prices. Together, these conditions led to price spikes in the day-ahead as well as 

the real-time markets.

CAISO also navigated a solar eclipse in August, during which real-time prices 

rose to over $22/MWh at the height of the eclipse from about $17/MWh at the 

beginning.
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During the winter cold snap beginning on December 26, 2017, and ending on 

January 7, 2018, PJM, NYISO, and ISO New England experienced peak loads 

near but not above their respective all-time winter high levels. For example, three 

of PJM’s ten highest load levels came in the first week of January 2018, although 

load was rising above usual winter peaks in late December 2017. Real-time 

locational marginal prices (LMPs) began to rise above $100/MWh on December 

26, 2017 in PJM and ISO New England, and increased suddenly to over 

$300/MWh in both markets on January 5-7, 2018. NYISO’s Zone J, which covers 

New York City, experienced LMPs above $1,000/MWh between January 5 and 

January 7, 2018.

In NYISO and ISO New England, record high natural gas prices enhanced the 

competitiveness of oil-fired generation. As a result, oil was relied upon to produce 

roughly one-quarter of the ISO-NE’s generation for two weeks and inventories 

stored at the region’s units fell from 4 million barrels at the beginning of 

December to about 1 million barrels at the end of the cold snap, or 19 percent of 

maximum available fuel oil capacity.

1 A majority of ISO-NE’s oil-fired plants 

participated in the ISO’s Winter Reliability Program, which enabled them to

 1 The oil inventory capacity in ISO New England is roughly 6 million barrels. The 

inventory was depleted to about 19 percent of capacity by January 8, 2018. For 

additional information, see page 21 of ISO New England’s report, “Cold Weather 

operations, December 24, 2017 – January 8, 2018,” <https://www.isone.com/static-assets/documents/2018/01/20180112_cold_weather_ops_npc.pdf> 
17

receive compensation for eligible, unburned oil at the end of the winter. In PJM,

coal-fired generation represented 40 percent or more of the total generation in 30 

percent of hours from December 26, 2017, through January 7, 2018, as high 

natural gas prices led to increased economic dispatch of resources with relatively 

lower fuel costs. Approximately 60 MW of economic demand response 

participated during the cold snap. Another 5,400 MW of emergency demand 

response capacity was available, although not called upon, in PJM. Weatherrelated events led to 24.2 GW of forced outages in PJM on January 7 and 4.5 GW 

of outages in NYISO on December 30. In ISO-NE, outages and reductions totaled 

6.9 GW on January 6, including the Pilgrim Nuclear Power Plant, which was out 

of service from January 5 through January 10, 2018.

From December 26, 2017, through January 6, 2018, natural gas demand averaged 

132 Bcfd, setting a new record at 148 Bcf on January 1, eight percent higher than 

the previous record. Natural gas prices in New York City, New England, and the 

Mid-Atlantic all set all-time record highs, with next-day trades reaching as high as 

$175/MMBtu in New York City on January 4. Although Operational Flow Orders 

limited shippers’ flexibility to exceed their contractual obligations to meet varying 

natural gas demand, there were no pipeline outages or firm service curtailments. 

To compensate for pipeline capacity constraints, New England had to turn to

pipeline deliveries from Eastern Canada and LNG shipments. 
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In 2017, average day-ahead on-peak LMPs increased between 3 and 13 percent at 

the pricing nodes throughout the ISOs, as seen by the color gradients on the map.

This mirrored increases in regional natural gas prices across the country 

mentioned earlier in the presentation. In SPP and PJM, average day-ahead onpeak LMPs increased by approximately 3.5 percent relative to 2016 levels. In ISO 

New England, NYISO, and MISO, the increase was between 5.4 and 7.2 percent. 

CAISO experienced the highest increases, with day-ahead on-peak LMPs about 13 

percent higher in 2017 relative to 2016. 

The pins on the map show that ISO and non-ISO trading hubs also experienced 

power price increases comparable to the nodal LMP increases, with the exception 

of PJM’s Western hub, whose average day-ahead on-peak LMPs were the lowest 

they have been since 2010. Despite these year-over-year price increases, power 

prices at the eastern trading hubs remained near their lowest average levels since 

2010. For example, between 2015 and 2016, average day-ahead on-peak prices 

declined at all the major trading hubs represented on the map, in some cases by as 

much as 28 percent, with the exception of the Indiana Hub. In the Western 

Interconnection, however, day-ahead on-peak power prices at Mid-Columbia and 

Palo Verde trading hubs increased by a wider margin—approximately 15 and 28 

percent, respectively—relative to 2016 averages. 

With the growth of solar integration in the CAISO, day-ahead LMPs reached 

negative values in over 50 midday hours across the CAISO market from January 

through June of 2017. However, day-ahead LMPs in CAISO exceeded $60/MWh 
19

during the evening ramping period at 8 pm during those six months. As the 

ramping needs in CAISO have grown, nearly 7 GW of ramping capacity were 

needed to meet load during the evening ramp in the last week of March 2017, 

when the ramping requirements reached their peak through the first quarter of 

2017.
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As shown in this chart, capacity prices dropped in each of the regions in auctions 

held during 2017.

The largest price change occurred in MISO, where prices fell to $0.05/kW-month 

for all zones, a major decrease from $2.16/kW-month the year before in Zones 2-

7. The low price reflected the region’s short-term resource adequacy, the vertical 

demand curve of MISO’s capacity auction and the prevalence of generators owned 

by integrated utilities who self-supply and offer into the capacity market at $0.

The three northeast systems also showed noteworthy price declines. In New 

England, prices were down 25 percent. There were no large generator retirements

and no large, new generators cleared in the forward capacity auction for 2020-21. 

However, the region added 640 MW of new energy-efficiency and demandreduction measures which cleared at the lower system-wide clearing price.

The closing price in PJM’s base residual auction for the 2020-21 forward period 

was 23 percent lower, and is notable as the first in which PJM has procured only 

capacity performance resources. This completes the three-year transition to fully 

implementing PJM’s Capacity Performance rules.2

 For this year’s auction, the 

system experienced both additions and retirements, however, the overall capacity 

level remained largely unchanged. Importantly, there was a reduction of 2,800 

 2 PJM Tariff, Attachment DD §5.5.A(a) (Capacity Performance Resources).
21

MW in the reliability requirement from the prior auction because of lower 

forecasted peak load. 

In NYISO, there was a 22 percent price decrease in the New York City spot 

auctions. This price drop mirrored New York Control Area auction results, which 

also declined in 2017, but contrasted with price increases in the spot auctions of 

the Long Island zone and the G-J Locality zone, which covers the Lower Hudson 

Valley leading into New York City. The demand curve of the spot auctions was

reset in 2017, which changed the Net Cost of New Entry calculations in NYISO.

In particular, local capacity requirements increased in the New York City, Long 

Island, and the G-J Locality zones in 2017, which also affected clearing prices.
22

Commission-jurisdictional RTOs and ISOs have used a standard offer cap in their 

energy markets since the Commission first approved them. Originally set at 

different levels across the regions, these caps came to be set at a uniform 

$1,000/MWh.

During the Polar Vortex period in the winter of 2013-2014, resources sought to 

raise offers above $1,000/MWh and were able to demonstrate that, with natural 

gas prices pushed above $100/MMBtu, their short-run variable costs exceeded the 

offer cap. Some RTOs and ISOs brought petitions to the Commission asking for 

permission to raise the cap temporarily to allow the higher offers. Similar 

temporary or permanent waivers were requested in subsequent winters.

The Commission, in Order No. 831, found that the ability of resources to exceed 

the existing cap is required to promote efficiency in pricing and to provide an 

incentive to resources to offer their capacity when most needed. Order No. 831

placed a requirement on all RTOs and ISOs to file tariff provisions allowing offers 

above $1,000/MWh when based on verified costs. In addition, a hard cap of 

$2,000/MWh will be set for offers to set LMPs. Verified cost-based offers above 

$2,000/MWh can, however, be recovered by resources through uplift.

The Order required the regions to file these tariff provisions in May 2017. CAISO 

requested and received a one-year waiver because it did not have an existing cost 

verification structure in place as did the other regions. The tariff provisions to 

meet the requirements of Order No. 831 have been accepted for ISO New 
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England, SPP, PJM, and New York ISO. MISO is due to make additional filings 

in May.
24

This slide shows the capacity additions and retirements of each Commissionjurisdictional RTO/ISO, as well as other regions in the contiguous United States, 

as reported by the U.S. Energy Information Administration (EIA).

3 PJM added 

2.8 GW of net natural gas-fired generating capacity, mostly in the form of 

combined cycle units, while roughly 1.9 GW of coal-fired capacity retired. Before 

retiring last year, the relevant coal units had operated between 23 and 65 years. 

According to EIA, ISO New England experienced a net decrease in generating 

capacity in 2017, with the notable retirement of Brayton Point, a coal-fired power 

plant in Massachusetts. SPP added 1.4 GW in wind capacity and about 1 GW of 

natural gas-fired capacity. In CAISO, over 1.6 GW of natural gas-fired generating 

capacity retired, while most of the reported capacity additions were utility-scale 

solar and wind. 

Outside the Commission-jurisdictional RTOs/ISOs, generation capacity additions 

and retirements in 2017 paralleled the trend from a year earlier. Nearly all of the 

capacity retirements outside the ISOs consisted of coal-fired generation.

Overall, 50 percent of all reported generation capacity additions nationwide in 

2017 consisted of solar and wind capacity. Between 2016 and 2017, wind and 

solar experienced the highest year-over-year increases in installed capacity in 

percent terms, with wind capacity increasing by 7.5 percent and solar photovoltaic 

capacity increasing by 25.3 percent. It is worth noting that because facilities with 

 3 U.S. Energy Information Administration Form EIA-860M.
25

nameplate capacity below 1 MW are excluded from EIA’s reporting on utilityscale capacity additions, total capacity additions can be understated for some 

technologies (such as solar photovoltaic). According to EIA, another 3.5 GW of 

small-scale behind-the-meter solar capacity are estimated to have come online 

nationwide during 2017. 
26

The growth of electric storage capacity across the Commission-jurisdictional 

RTOs/ISOs, as well as other regions, over the past 10 years, continued in 2017. 

Battery storage capacity has seen the most rapid growth in recent years. PJM was 

the first RTO with a significant number of newer electric storage technologies (i.e. 

batteries and flywheels) clearing its market to provide frequency regulation to the 

bulk power grid, and has the largest share of battery storage capacity. Since 2015, 

battery storage deployment in CAISO has grown rapidly due to a number of 

events. First, the CPUC mandated the California investor-owned utilities (IOUs) 

to procure 1.3 GW of electric storage resources by 2020. Second, after the 

retirement of the San Onofre Nuclear Generating Station, the IOUs procured 

battery capacity to meet local capacity requirements. And third, following the leak 

at the Aliso Canyon natural gas storage facility, three large batteries totaling 70 

MW of capacity were deployed in southern California. NYISO is also seeking to 

increase battery storage capacity by making storage development a component of 

the State’s clean energy strategy and aligning it with New York State’s Reforming 

the Energy Vision initiative. As reported to EIA, excluding Alaska and Hawaii, a 

total of 134 MW of battery storage projects began operating in 2017.

Recognizing the technical capabilities of electric storage resources to participate in 

the capacity, energy and ancillary service markets, the Commission issued Order 

No. 841 in February 2018, which requires the RTOs/ISOs to remove barriers to 

the participation of electric storage resources in their markets by creating a 

participation model, or a set of market rules, that acknowledges the physical and 
27

operational characteristics of electric storage resources.4 Order No. 841 specified 

that the participation model for electric storage resources must: (1) ensure that a 

resource using the participation model is eligible to provide all capacity, energy, 

and ancillary services that it is technically capable of providing; (2) ensure that a 

resource using the participation model for electric storage resources can be 

dispatched and can set the wholesale market clearing price as both a wholesale 

seller and wholesale buyer; (3) account for the physical and operational 

characteristics of electric storage resources through bidding parameters or other 

means; and (4) establish a minimum size requirement for participation in the RTO 

and ISO markets that does not exceed 100 kW. The Order also requires that the 

sale of electric energy from an RTO or ISO market to an electric storage resource 

that the resource then resells back to that market must be at the wholesale LMP. 

The ISOs and RTOs were given 270 days to file tariff provisions that comply with 

Order No. 841, and they will have an additional 365 days to implement those tariff 

provisions. 

 4 Electric Storage Participation in Markets Operated by Regional Transmission 

Organizations and Independent System Operators, Order No. 841, 162 FERC ¶ 

61,127 (2018).
28

Over 680 miles of new transmission lines were added across the country in 2017, 

but mostly in MISO and PJM. NYISO and CAISO did not add transmission.

Although not an addition of new transmission, the entry of Portland General 

Electric into the Western Energy Imbalance Market (EIM) opened up more 

transmission available for imbalance energy transfers among the participating 

balancing authorities. 

In addition to the transmission lines completed in 2017, several ISOs approved 

transmission projects using the competitive bidding processes approved by the 

Commission to comply with the requirements of Order No. 1000. MISO’s Board 

of Directors approved a transmission plan that included The West of the 

Atchafalaya Basin (or WOTAB) project, a 500-kV project in Entergy’s service 

territory in western Louisiana and eastern Texas. The WOTAB project is the 

second transmission project subject to competition in MISO, pursuant to Order 

No. 1000. Similarly, NYISO’s Board of Directors approved a transmission project 

submitted by NextEra Energy to address congestion and deliverability constraints 

in the West Zone, which experienced higher congestion levels in 2017 than in 

prior years. This was the first transmission project selection in NYISO made 

using the competitive bidding process under Order No. 1000.
29

This slide shows the current entities in the Western EIM, which as of April 1st

2018, includes Idaho Power Company and Powerex. Seattle City Light, Salt River 

Project, the Sacramento Municipal Utilities District, and the Los Angeles 

Department of Water and Power will likely join the EIM by 2020. As the EIM 

footprint has grown since its inception in November 2014, more energy has been 

provided for imbalance services in the market and CAISO has sold surplus 

renewable energy that may have otherwise been curtailed to balance load on its

system.

In 2017, the EIM provided a mechanism to manage the disruption to net load and 

utility-scale solar generation caused by the solar eclipse on August 21st. To 

prepare for that event, CAISO worked with other Balancing Authorities (BAs) in 

the EIM to include the prospective impact of the eclipse in their forecasts so that 

planning reflected available supply and expected load. CAISO, Puget Sound 

Energy, PacifiCorp West, PacifiCorp East, NV Energy, and Arizona Public 

Service met their imbalance demands through transfers inside the EIM and 

reliance on natural gas-fired generation. 

The EIM continued to experience price separation in 2017 between the BAs in the 

Pacific Northwest and the BAs further south. In particular, transfer limits and the 

available transmission contributed to price differences between EIM Entities in the 

Pacific Northwest—namely, PacifiCorp West, Portland General Electric, and 

Puget Sound Energy—and the rest of the EIM footprint. Staff is monitoring these 

price differences within the EIM.
30

This slide also shows the participants of the Mountain West Transmission Group 

(MWTG). The MWTG participants are a subset of the WestConnect planning 

region and are members of the Colorado Coordinated Planning Group. MWTG 

includes two investor-owned utilities, two municipal electricity providers, two 

generation and transmission cooperatives, and two federal power marketing 

administration projects. In January 2017, SPP and MWTG signed a non-binding 

letter of understanding to discuss potential membership with SPP and in 

September MWTG announced they were beginning formal negotiations with SPP 

for RTO membership. The SPP Public Stakeholder Process began in October 

2017. Staff continues to stay abreast of key developments related to the potential 

integration. 
31

The Electric Quarterly Reports (EQR) summarize data on electric power contracts 

and wholesale power sales by utilities with rates on file, as required by section 

205(c) of the Federal Power Act. The EQR provides data to the public and market 

participants, which increases transparency in wholesale energy markets. 

As shown in the figure above, the Northwest region reported the largest volume of 

hourly sales of energy and booked out power at market-based rates in 2017 among 

bilateral (non-RTO/ISO) markets. The large volume of hourly market-based rate 

sales in the Northwest continues a trend seen in past years and reflects the 

structure of the bilateral markets in that region. The Northwest has robust trade in 

short term products, which is reflected in the large number of sellers reporting 

trades in the region. 

The volume-weighted price for hourly market-based rate sales reported to the 

EQR in non-RTO/ISO markets in 2017 closely tracked the annual reported price at 

nearby trading hubs discussed earlier in this presentation. The reported volumeweighted price for hourly market-based rate sales was highest in the Southwest 

(approximately $34/MWh), followed by the Southeast (approximately $27/MWh) 

and the Northwest (approximately $26/MWh).