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June 30th, 2014

Notes from the 2014 LDC Gas Forum‚??s Northeast Gas Buyer‚??s Panel Discussion

by Andrew Price, President & COO

I had the opportunity to speak again at this year’s LDC Gas Forum in Boston as a member of the Gas Buyer’s Panel. The three-day LDC Gas Forum attracts a diverse set of players from the natural gas industry. Local distribution utilities,pipelines, marketers, traders, producers, consultants and large end-users are all in attendance.

This year my panel included three utility veterans. Nick Petruzzella is the General Manager of Six Nations Natural Gas, a small natural gas distribution utility on the Six Nations of the Grand River Territory in Ontario, Canada. Chris Shorts directs gas purchases for the 1.4 million sales customers of Union Gas, a Canadian natural gas storage, transmission and distribution company based in Ontario. Ken Yagelski is the Director of Gas Supply Policy for AGL Resources, a S&P 500 company which provides gas to 4.5 million consumers via subsidiaries Atlanta Gas Light (Georgia), Chattanooga Gas (Tennessee), Elizabethtown Gas (New Jersey), Elkton Gas (Maryland), Florida City Gas (Florida), Nicor Gas (Illinois) and Virginia Natural Gas (Virginia). Last but not least was Jack Maydick, Senior Director at CME Group, who was the panel moderator and kept the conversation rolling. 

As the only non-natural gas utility representative, I attempted to represent the interests of CES clients in the industrial, commercial and institutional sectors. CES clients generally purchase their own natural gas in the competitive marketplace – instead of utility provided default or standard offer supply - and look to their local utility for delivery of the natural gas once it has been dropped off at the utility “citygate.”

For this week’s blog I have included the questions that were asked as well as the answers I gave (or intended to give). Given the very high prices plaguing New England, and the Boston venue, I focused my comments on New England.  

1. How is the price of gas affecting usage? Are customers switching to natural gas from alternate fuels, or to alternate fuels from natural gas?

Winter basis prices in New England are having a large impact on a number of CES clients. Several large industrials elected to curtail operations – reducing gas usage significantly - on the highest priced days. These clients are leaving no stones unturned in advance of next winter – considering alternative fuels, trucked gas imported from outside the region, as well as various hedging alternatives. And they are very engaged with their political representatives – pushing them to support additional pipeline capacity into New England. Cost containment during the next several winters, which will almost certainly have very high and volatile natural gas prices, will be critical to the survival of much of the region’s industrial base.

At the same time, regional gas utilities – like Summit Natural Gas in Maine - are opening up new areas to pipeline natural gas service. Businesses in these regions had long relied on oil and propane, but are rapidly converting to pipeline natural gas service. In light of recent and expected price volatility in the natural gas basis market, they are generally maintaining their old fuel as a backup whenever possible, making fuel arbitrage a possibility when natural gas prices spike on peak winter demand days.   

2. How did the Polar Vortex and related natural gas price impacts affect your purchasing strategies?
How will this winter impact your purchasing going forward?
Do you plan on using more or less long-term supply contracts vs. long-term hedging agreements? Will they start to make a comeback after this winter?

The price spikes this winter had an enormous impact on purchasing and operating strategies. CES had a large number of dual fuel clients actively arbitraging between natural gas and oil or propane. In some cases clients were selling previously hedged gas back – when prices reached levels that more than offset the otherwise applicable fuel cost. In other cases, clients modified operations, seeking to hit their contracted volumes exactly so that they were not exposed to high market based cash-out prices. 

The reaction to last winter’s price spikes is very customer specific. Some clients have strong desire for Full Requirements type contracts after a winter with lots of high cash-out prices on daily and monthly cash-out products. Others are willing to consider taking smaller basis positions during Jan/Feb in the near term hoping that basis prices might moderate later in the summer or fall. The default position for these clients if basis pricing does not fall to target levels will be to burn spot gas during low priced winter days, converting to their alternative fuel when natural gas prices spike.

Extending a hedge term can reduce basis price modestly but typically not enough to drive terms over 24 months. Given the number of pipeline expansion projects that could significantly reduce basis pricing during the next 2-5 years, timing is a big concern in this market.

3. How do the increasing shale supplies affect your gas purchasing and contracting practices?
a. Did shale help to mitigate what might have been an even more volatile winter season?
b. Will we finally see new transport constructed in the Northeast?

The anticipation of new pipeline capacity and continued expansion of shale gas production has a large impact on term selection. Most are anticipating a much lower basis differential for New England by 2018 and are keeping hedges short in anticipation of lower pricing. In the near term, seeing zero or even negative basis in Pennsylvania - on the same days that basis spiked to $40, $50, even $70 per MMBtu in New England - added significantly to the gloom of a long cold winter in New England.

4. Given the efforts of gas-electric coordination and the recent FERC NOPR, what are your concerns for future operations?

The FERC NOPR issued March 20, 2014 is likely to impose some costs on natural gas pipelines which would presumably be passed along to my clients. These changes may be offset by gains on the power gen side of the ledger, as generators can more easily schedule and modify natural gas requirements, resulting in a net win for energy consumers.

The real issue in New England, however, is not addressed by the NOPR. The larger issue is that power generators have not been able to provide the long term commitment to firm pipeline capacity (like LDCs can) that is required to support the construction of adequate natural gas pipeline capacity. CES has been very active advocating for at least 2 BCF of incremental pipeline capacity into New England. The small surcharge that would be required to pay for the pipeline capacity would be tiny compared to the overall savings that could be achieved in the form of lower power and natural gas rates. The primary challenge is determining how to assign the surcharge to rate payers while providing the binding long term commitment required for the pipelines to move forward. The simple payback on a full 2 BCF of incremental natural gas pipeline capacity would be about 1 year! This is clearly a no-brainer investment.

5. In light of this winter, will the DOE continue to grant LNG permits?

My understanding is that DOE is not the limiting factor – DOE applications are relatively cheap – as evidenced by the eight approvals it has issued. FERC approval is much more expensive and difficult, and only two have been issued to-date at existing LNG import facilities. DOE just announced that it would delay issuing new conditional permits to export to non-FTA approved countries until after the environmental review process is completed. FERC’s environmental impact review may also be delayed as the new GHG restrictions announced by the EPA are incorporated. The complexity of financing, constructing and contracting for offtake from these facilities, as well as competition from other regions like Australia and East Africa, is likely to limit the market to a half dozen or less LNG export facilities before 2020.

6. Have you seen an impact from new natural gas demand for vehicle fueling (CNG and LNG)?

We saw a big surge in interest in trucked natural gas across our client base over the past two years. This was focused on those with no access, or constrained access, to pipeline natural gas. Close to a half-dozen strong competitors entered the LNG and/or CNG markets in the Northeast. The limited options for liquefaction in New England, and the location of most CNG compression stations from within the pipeline constraint, was devastating for the trucked gas business this past winter. Most end users with trucked gas contracts were converted back to their alternative fuels for much of the winter, as natural gas spot prices exceeded the cost of propane and oil.

7. Given the current state of storage inventory, have you adjusted your storage-injection plan? Do you think the industry will fill storage to levels required for the next heating season?

As a buyer for end users we have no injection plan but are certainly following the weekly EIA injection report extremely closely! So much depends on the summer we get, but I believe storage will get to a level that is adequate, if not entirely comfortable, for next winter. Price levels may need to remain high enough for coal to economically displace natural gas for power gen and to incentivize new well completions.

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