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In This Issue

Pipelines and Electric Bills

Despite Slower Power Forecast, Skiffes Line Needed, Grid Operator Says

Natural Gas and Oil Market Update

EIA - Weekly Natural Gas Storage Report

NYMEX Natural Gas Week-to-Week Price Change

Natural Gas Futures - Five Year Price


NOAA 6 to 10 Day Outlook
Color indicates the probability of forecasted temperatures being above or below a historical average for the period.


Market Overviews

Pipelines and Electric Bills

NH Business Review | March 17, 2017

The ongoing debate over how New Hampshire can help businesses reduce their energy costs may become more heated as a result of a new study just released by the University of New Hampshire.

The study warns that New Hampshire electric customers could see their bills increase over time if they are asked to pay for interstate pipelines that would bring more natural gas into New England. Alternatives like energy efficiency, renewables and energy market adjustments are shown to provide better returns with less risk to ratepayers. 

“New Hampshire’s Electricity Markets: Natural Gas, Renewable Energy and Energy Efficiency” comes on the heels of a novel and arguably risky proposal that would allow electric distribution companies to purchase natural gas capacity, recover the costs of these purchases from ratepayers, and then release the gas into the market in order to bring electricity prices down and provide price relief to electric customers.

The report notes the problems with developers’ studies showing that electric customers would see lower electricity bills. It also cautions against using ratepayer-funded rather than private funding mechanisms to finance gas pipeline expansion, because this poses a “significant risk” of locking ratepayers into higher electric bills for decades. 

The report should shed some light on whether bringing more energy supplies into the region using ratepayer dollars is the best way to bring down electric bills.

Almost half of the power generated in New England comes from gas-fired power plants and, when cold snaps require most of the gas to be used for heating rather than power, electric ratepayers can see price spikes. The regional grid operator and state officials have called for more gas to be brought into the region, but do not specify how. Interstate pipeline expansion and local delivery of liquefied natural gas are two options being considered, but both present challenges.

Private financing for gas transmission expansion relies on long-term contracts with gas distribution companies that provide heating supplies. The power plants that produce electricity rarely enter long-term contracts for fear that they will not be able to recover their investment. 

One developer, Kinder Morgan, withdrew its proposed pipeline expansion project last year for lack of long term gas purchase commitments. The remaining pipeline expansion proposal, “Access Northeast,” is being promoted by PSNH/Eversource and its development partners.

To get around the private financing challenge, Eversource has asked regulators to consider an approach that would rely on long-term contracts between natural gas pipeline companies and electric distribution companies. The proposal was rejected by Massachusetts courts last year. The NH Public Utilities Commission has also rejected the proposal. In February, Eversource appealed the commission’s decision to the NH Supreme Court, and a decision is pending. The Legislature is also considering an amendment to state law that could open the door to the type of ratepayer financing being proposed for Access Northeast. 

But the UNH report casts doubt on the need for ratepayer-funded solutions or immediate government intervention to address energy demand and cost control. It shows that there is no near-term threat to grid reliability and that current pipeline capacity is adequate as a result of substantial upgrades.

Large investments in New England’s electric transmission infrastructure over the past 15 years have increased reliability but, ironically, have substantially increased electric bills. Even so, the report shows that, although the regional price per kilowatt has been higher than the national average for decades, New Hampshire’s average commercial electricity bill is lower than both the regional and national averages with comparable business activity and GDP. 

For example, the report shows that in 2015, the average monthly commercial electric bill in New Hampshire was $529, compared to the $670 U.S. average and the New England monthly average of $786. At the same time, New England has grown economically by reducing energy usage through energy-efficiency measures and changing to a less energy-intensive economy. Looking forward, the report shows only modest increases in regional demand while, at the same time, New England’s grid operator just announced a drop in 2016 electricity demand. 

After analyzing alternatives, the report and an accompanying policy paper, “New Hampshire’s Electricity Future,” recommend more focus on “soft” infrastructure changes — market adjustments, better contracting practices, combined with measures like short-term arrangements for local delivery of LNG, energy efficiency and local renewable energy. The analysis shows these measures will have at least as large a return on investment without exposing ratepayers to higher electric bills from committing ratepayer dollars to assist in financing costly private energy projects.

Requiring the rigorous analysis needed to show that consumers will reap significant benefits from large projects is also recommended, as economic studies submitted to date simply conclude, without sufficient or transparent analysis, that wholesale electric rates would be reduced by pipeline expansion. A fully competitive process in choosing projects is also recommended.

The report and policy paper are essential reading for policymakers considering fundamental changes to New Hampshire’s statutory scheme, which is geared toward competitive energy markets that are designed to provide the lowest possible cost to electric customers.

Read More:

Despite Slower Power Forecast, Skiffes Line Needed, Grid Operator Says

Daily Press | March 17, 2017

Despite revised forecasts showing much slower growth in electricity use in the decade to come, Dominion Virginia Power could still run into problems ensuring reliable supply if it can't beef up its high voltage connections on the Peninsula with a line across the James River, the manager of the 13-state regional power grid serving Virginia says.

And a new set of alternatives to Dominion's proposed 500 kilovolt line from Surry County to Skiffes Creek in James City County suggested by the National Trust for Historic Preservation won't address several power supply trouble spots, that manager, PJM Interconnection, told the Army Corps of Engineers.

The line can't be built unless the Corps approves. Dominion and PJM say the line is needed because the utility must shut down its two aging coal-fired generating units at Yorktown this spring to meet new federal limits on emissions of mercury and other toxic gases. Without those units, high voltage lines and equipment are at risk of becoming overloaded, triggering blackouts.

Dominion, the State Corporation Commission and PJM say the transmission line across the James is the most efficient way to prevent blackouts.

But the National Trust, joined by other preservation and environmental groups, said the line would permanently disfigure the James River at Jamestown, which the trust has named as one of the 11 most endangered historic sites in the United States.

The trust proposed four alternatives to the Surry-Skiffes Creek line in October.

In a letter to the Corps earlier this month PJM vice president Steven Herling said the grid manager's reviews found that none would fix all supply challenges the Peninsula faces.

National Trust officials did not respond to requests for comment.

Herling said the Surry-Skiffes Creek line is still needed even though its forecasts for power demand in Dominion's territory, which covers about two thirds of Virginia and northeastern North Carolina, shows much slower growth than earlier forecasts. Critics of the power line project have argued that Dominion's forecasts for power demand were unrealistically high.

The latest PJM forecasts, meanwhile, suggest peak load demand during the summer would grow at an annual rate of 4 percent though 2027, to reach a total of 20,501 megawatts.

That's 1,755 megawatts less than PJM's forecast a year ago, nearly an 8 percent decline. Last year, Dominion's summer peak was 19,539 megawatts.

PJM told the Corps that the National Trust's four alternatives wouldn't address problem spots with electric supply that the $236 million Surry-Skiffes Creek line resolves. That cost estimate excludes costs to mitigate impact on the environment that the Corps is likely to impose if it approves the line. Currently that cost is estimated at $85 million.

Three of the trust's proposals call for increased use of Yorktown's oil-fired generating unit. Dominion has said those three would cost anywhere from $570 million to $1.9 billion.

And using the Yorktown oil-fired unit would not address problems with overheated high voltage lines and voltage swings, PJM's Herling said.

A fourth alternative, which calls for a new 18 mile 230 kilovolt line and a new 25 mile 230 kilovolt line, together would impact more than 80 acres of wetlands, cut through residential areas and cross the Chickahominy River at a point considered sacred by the Chickahominy Tribe. The right-of-way acquisition, the new permitting process with the Corps, the length of the lines and the cost of mitigating impacts on wetlands, homeowners, businesses and the Chickahominy mean this project would take much more time, leaving the Peninsula exposed to the risk of blackouts for seven years, Dominion said.

Dominion's request for permission to build the James River line has been pending before the Army Corps of Engineers since August 2013.

Earlier this year, Dominion disclosed an emergency plan for cutting power, with no notice, to 150,000 customers in Hampton, the Tabb, Grafton and Seaford areas of York County, Poquoson and most of Newport News if there are faults in two of the dozens of components on its high-voltage transmission network on the Peninsula, such as substation transformers, breakers and sections of wire between breakers.

That kind of two-component fault has happened twice in the past decade, according to Steven Chafin, Dominion's director of transmission planning.

But the failure of a single component could trigger rolling blackouts in the region, including James City County, Williamsburg and upper York County as well as the communities that would be hit by the emergency plan.

The utility has seen six such single-component failures in the area during the past decade.

Opponents of the Surry-Skiffes Creek line have said Dominion's warnings about rolling blackouts are simply a scare tactic. Dominion has said there could be as many as 80 days a year in which demand for power is so high that rolling blackouts are possible.

Read More:

Natural Gas and Oil Market Update


Weekly US Natural Gas Consumption Rose, Impacted Prices

Market Realist | March 17, 2017

April natural gas (UGAZ) (FCG) (DGAZ) futures contracts fell 2.7% and settled at $2.9 per MMBtu (million British thermal units) on March 16, 2017. Broader markets like the S&P 500 (SPY) (SPX-INDEX) also fell 0.2% on March 16, 2017. Oil and gas are major parts of the energy sector. The energy sector contributed to ~6.5% of the S&P 500 as of March 17, 2017.

NYMEX natural gas prices fell from a one-month high due to the following factors: less-than-expected draw in US natural gas inventories last week and mild winter weather. However, prices have risen 13% from their three-month low of $2.6 per MMBtu on February 21, 2017.


Oil Prices Barely Budge, But Aim For First Weekly Gain In Three

MarketWatch | March 17, 2017

Oil barely budged on Friday, even as data showed a significant increase the number of active U.S. oil rigs, leaving prices on track to tally their first weekly gain in three weeks. Data from Baker Hughes BHI, +0.79% Friday revealed that the number of active U.S. rigs drilling for oil, a proxy for oil activity, continued the streak of increases that began in mid-January.

April West Texas Intermediate crude CLJ7, +0.02% rose 2 cents, or less than 0.1%, to $48.77 a barrel on the New York Mercantile Exchange. May Brent crude LCOK7, -0.02% on London’s ICE Futures Exchange rose a penny to $51.75 a barrel.

EIA - Weekly Natural Gas Storage Report

EIA - Weekly Natural Gas Storage Report

Working gas in storage was 2,242 Bcf as of Friday, March 10, 2017, according to EIA estimates. This
represents a net decrease of 53 Bcf from the previous week. Stocks were 236 Bcf less than last year
at this time and 395 Bcf above the five-year average of 1,847 Bcf. At 2,242 Bcf, total working gas is
within the five-year historical range.

NYMEX Natural Gas Week-to-Week Price Change NYMEX Natural Gas Week-to-Week Price Change

Natural Gas Futures - Five Year Price ($ per mmBtu)

NYMEX Natural Gas Week-to-Week Price Change - Five Yearly Snapshot

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