Energy Management

December “Energy Market Outlook Webinar” Recap – Q&A

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Our December “Energy Market Outlook Webinar,” focused on several topics, including the energy-related weather outlook, key market price drivers and the energy policy impact of a new administration in the White House. The webinar, which you can access by clicking here, inspired a few questions from some of our guests. We answer them below with input from principals in our Commodities Management Group.

Q: Will we see the natural gas price go up to $4/MMBtu with just a normal winter? Will we see a normal drop in gas pricing in the March/May time frame?               

A: Possibly, yes—to both questions. After peaking at an intraday high of $3.994/MMBtu back on Dec. 28, which is the highest level seen since December 2014, the NYMEX prompt-month contract has already retreated $0.76/MMBtu, or -18 percent, as a result of warming temperature forecasts for the eastern two-thirds of the nation through much of January.

Weather represents a large piece of the overall energy price picture, so expect some volatility as forecasts shift during the next few months. Together with natural gas production and storage, weather will be a big contributor to where gas prices go in the March/May time frame. Other factors include increased liquid natural gas (LNG) exports, Mexican exports and higher industrial demand, which all look to keep prices in the mid-$3 area, which is somewhat higher than the current price ($3.07) we see in the Calendar 2018 NYMEX strip.

As the back of the NYMEX curve muddles, fundamentals are lining up to keep 2017 supported and 2018 bullish. We began withdrawal season with a record storage level (inventories reached 4,047 Bcf on Nov. 11, which put the storage surplus at 1.5 percent above last year’s level and 7 percent above the five-year average).  As of mid-January, storage inventories now stand at 2,917 Bcf, widening the storage deficit to -13 percent (-431) below year ago levels and -2.6 percent below the five-year average. We’re projecting that about 1.7-1.8 Tcf will be left in the ground in late March; which could mean additional price support.

Keep in mind that prices vary widely over any given period of time. For example, they hit a 17-year low of $1.61 in March 2016 after one of the warmest winters on record resulted in record levels of underground natural gas storage. Prices then gradually increased to $2/$2.50 until a warm summer helped increase demand and burn through some of the storage surplus, which again drove prices up to the $3 range.

Tip for buyers: In 2016, we talked a lot about prices being at, or near, all-time lows. Plus, we see prices for future years backwardated in many markets, which basically means that the further out you look, prices are trading at a discount to current prices. This scenario provides an opportunity to protect against some of the run-ups in the market that are largely driven by weather. It also offers buyers an opportunity to lower average energy costs by contracting for extended terms.

Q: Given the fact that the ratepayers won’t be underwriting the cost of several major pipelines, including Access Northeast, we are getting mixed messages regarding the future of the pipeline project.

A: The Access Northeast project would upgrade Spectra Energy’s existing Algonquin natural gas pipeline system in Connecticut and Massachusetts. Spectra partnered with electric distribution companies (EDCs) Eversource Energy in New Hampshire and National Grid in Massachusetts for project development, since the project is designed primarily to get natural gas to the gas-fired power plants that feed the New England grid.

Supporters of the project say Access Northeast is the most benign way to get extra natural gas into New England to help lower electricity prices, particularly in the winter. Yet, Massachusetts, New Hampshire and Connecticut have all rejected Eversource’s idea to cover the cost of buying gas over 20 years with money paid by electricity users, which represented 84 percent of the project’s total $3 billion cost.

Spectra is currently re-evaluating the project, and will potentially resubmit to the Federal Energy Regulation Commission (FERC) in mid-2017.

Spectra’s pipeline project is not the first to falter this year. In April, construction of the Northeast Energy Direct (NED) pipeline across southern New Hampshire was abandoned by Kinder Morgan. The company couldn’t get enough long-term commitments from electricity producers to justify the multibillion-dollar expense.

Q: If storage levels reach the EIA [1.946 Tcf] or Constellation [1.75 Tcf] end-of-winter levels, what could buyers with April-June contract end dates face in regards to spring pricing?

*Please note the EIA has revised its end-of-winter level to 1.745 Tcf as of Jan. 10.*

A: Supply and demand fundamentals are key short- and long-term price drivers. Current underground inventories stand at 2.9 Tcf, bringing the storage deficit to -13 percent below year ago levels. That’s pretty impressive considering we started the refill season with a surplus of 1,000 Bcf in mid-March. The market helped manage the surplus—with low gas prices, which depressed production levels and allowed for below-average injection through the summer, and demand that drove increased power burns.

What we expect to see now is the market’s focus turn to end-of-March storage levels. The rate at which the surplus widens or narrows, which is largely dependent on weather, will be important as we move through the winter withdrawal season. Right now, there’s still plenty of gas in the ground but weather and increased demand will manage some of that storage down further; and even a normal winter can dig further into the stockpile.

NYMEX natural gas prices are highly correlated to inventory surplus or deficit. Generally, in an oversupplied market, you’ll see suppressed prices, and when you have a supply shortage that will be supportive of prices. As stated above, some analysts anticipate a spring price in the mid-$3 range.

Q: What has driven up the price of NYMEX CAPP GasEquiv (coal) price since last August?

A: Cuts in Central Appalachian (CAPP) production have impacted supply; supply and demand factors continue to provide support for coal prices. The U.S. Energy Information Administration (EIA) estimates that coal production declined by 158 million short tons (MMst) in 2016, to 739 MMst, which is the lowest level of coal produced since 1978.

While coal consumption also decreased in 2016, by 60 MMst (8 percent)—as the result of competition with low-priced natural gas and relatively mild temperatures in the first half of the year—the EIA expects it to increase by 41 MMst in 2017. The rebound is due to rising natural gas prices and increasing electricity generation.

EIA estimates the delivered coal price averaged $2.13/MMBtu in 2016, a 4 percent decline from the 2015 price. Coal prices are forecast to increase in 2017 and in 2018 to $2.18/MMBtu and $2.21/MMBtu, respectively.

Some anticipate the policies of the incoming administration to be more supportive of coal as an energy resource.  Trump outlined his vision to make America energy-independent during his run for president, including plans to “unleash America’s $50 trillion in untapped shale, oil and natural gas reserves, plus hundreds of year in clean coal reserves.” He also pledged to “open onshore and offshore leasing on federal lands, eliminate moratorium on coal leasing, and open shale energy deposits.”

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