NOAA 6 to 10 Day Outlook
Color indicates the probability of forecasted temperatures being above or below a historical average for the period.
New England Natural Gas Pipeline Projects Needed Sooner Than Later
Energy Biz | December 19, 2013
Last winter, New England experienced the highest average natural gas and electricity prices in the country. On any given day, New England natural gas markets have the highest and most volatile spot prices in North America. When temperatures plummet during the peak of winter, weather demand increases at such a rapid rate that major gas pipelines across the region become constrained.
That was the case last winter when local temperatures reached 15 to 20 degrees below average, resulting in flow volumes at or near maximum pipeline capacity. Exacerbating the situation is the fact that more than half (52%) of the electricity produced in New England comes from gas-fired generators, there has been a drastic drop-off of LNG imports into the region and offshore Canadian production has been a disappointment.
In New England, as with most markets, power prices move in step with regional gas prices. When pipelines get constrained, the price of gas in the delivery area rises, and in turn, so does the cost of electricity. New England is a primary target for the vast amount of Marcellus Shale gas being produced in nearby states. The problem is getting it there. The solution to New England’s high energy prices is improved gas pipeline capacity. But, herein lies another problem: pipeline projects can take years to complete from the planning stage to actual operation, and for New England, there is nothing on the horizon until at least 2016.
The largest project in the planning stages right now is Spectra Energy’s Algonquin Incremental Market Project. As currently proposed, the project outlines the replacement of 25.6 miles of various segments of the existing mainline relay and loop, and includes 1.2 miles of new pipeline to be installed beneath the Hudson River using a horizontal directional drill. Once completed, the pipeline will have the capacity to bring up to 0.433 Bcf/day of natural gas, primarily Marcellus Shale gas, to New York, Connecticut, Rhode Island and Massachusetts. The project is expected to be completed in 2016.
Kinder Morgan Energy Partners is proposing to expand its Tennessee Gas Pipeline (TGP) with at least two major projects. The first, the Northeast Connecticut Expansion Project, will bring an additional 0.072 Bcf/d to New England by November 1, 2016. The project calls for approximately 13 miles of new pipeline loops along TGP’s 200 Line system in New York, Massachusetts and Connecticut, and would increase capacity from Tennessee's existing interconnect with Iroquois Gas Transmission in Wright, New York, to Zone 6 delivery points on Tennessee's 200 and 300 lines.
Kinder Morgan’s second project is the construction of their Bullet Line, running 150 miles from Wright, NY to Dracut, MA. This will be a 30” high pressure line with a capacity of 1.2 Bcf/d, and will directly benefit the Boston area. This would be the third pipeline serving the highly congested region, and Kinder Morgan hopes to have the project in service sometime in 2017 or 2018.
For the next two winters, New Englanders can expect the same price spikes and high volatility in energy prices as they saw last winter. Nothing has changed since then, and not much can be done in the interim. LNG imports are available, but only at a price high enough to compete with international markets, and Canadian production from Deep Panuke will, at best, replace the declining production from Sable Island. But after 2016, if all projects go as planned, gas pipeline congestion should be significantly reduced, and with Marcellus gas flowing into the New England market, the energy landscape for this region will be vastly different. But there are still two primary risks to the construction of the new pipes. 1) There are significant upfront capital costs to build a new pipeline. 2) And NIMBY (not in my backyard) is a frequent obstacle for energy infrastructure, especially in a densely populated region like New England. So stay tuned because the outlook can change quickly.
EIA: Natural Gas to Overtake Coal by 2035
POWER Magazine | December 19, 2013
The latest projections from the Energy Information Administration (EIA) are unlikely to quell concern in the coal industry, as the EIA has increased its projections for natural gas production and power burn, while continuing its gloomy outlook for coal.
The EIA’s Annual Energy Outlook Early Release, posted Dec. 16, boosts its estimates of natural gas production from the 2013 outlook by about 11%, reflecting continued growth in shale gas development. While gas price estimates are slightly higher in the near term, the higher production levels caused the EIA to lower its price projections through 2040. This added production makes the U.S. a net exporter by 2018, two years earlier than last year’s projection.
Though the 2013 outlook had coal maintaining its lead over gas through 2040 (with 35% vs. 30%), the 2014 estimates change this outlook considerably, projecting that gas will pass coal by 2035 and take a 35% share of power generation by 2040 as coal falls to 32% (Figure 1). The primary drivers are reduced projections for gas prices and continued regulatory-induced coal plant retirements, while little new coal capacity is added. Installed coal capacity is projected to fall from 310 GW in 2012 to 262 GW in 2040.
Nuclear is also projected to lose market share slightly, as new construction and uprates are offset by retirements in the near term, though total installed capacity is projected to remain more or less level by 2040.
Renewables continue their strong growth, reaching parity with nuclear by 2040. Non-hydro renewables represent 28% of overall growth in electricity production from 2012 to 2040 in the 2014 Outlook. (Notably, the Outlook does not assume further policy support beyond expiration of current legislation, and notes that extensions or new policies could have “a large impact” on renewable generation.)
The shift toward gas and renewables drives a continued decline in the nation’s CO2 emissions, with the 2014 outlook projecting that 2040 levels will be 7% below 2005, compared to a 5% decline projected last year.
Natural Gas and Oil Market Update
Natural Gas Prices Rally After EIA Data
MarketWatch | December 19, 2013
Natural-gas futures on Thursday rallied after the U.S. Energy Information Administration reported that supplies of natural gas fell 285 billion cubic feet for the week ended Dec. 13. The fall was much more than expected as analysts surveyed by Platts forecast a drop of between 260 billion cubic feet and 264 billion cubic feet. Total stocks now stand at 3.248 trillion cubic feet, down 488 billion cubic feet from a year ago and 261 billion cubic feet below the five-year average, the government said. January natural gas was at $4.37 per million British thermal units, up 12 cents, or 2.9%. It was trading around $4.33 before the data.
WTI Trades Near One-Week High as Stockpiles Decline
Bloomberg | December 19, 2013
West Texas Intermediate traded near the highest price in a week after crude stockpiles declined in the U.S. and the Federal Reserve said it will reduce stimulus as the nation’s economic outlook improves.
WTI for January delivery, which expires today, was at $97.83 a barrel, up 3 cents, in electronic trading on the New York Mercantile Exchange at 1:11 p.m. London time. It climbed 58 cents to $97.80 yesterday, the highest settlement since Dec. 10. The more-active February contract gained 8 cents to $98.14. The volume of all futures traded was about 58 percent below the 100-day average. Prices are up 6.6 percent this year.
Brent for February settlement climbed 62 cents to $110.25 a barrel on the London-based ICE Futures Europe exchange. The European benchmark crude was at a premium of $12.06 to WTI for the same month, compared with $11.42 yesterday.
EIA - Weekly Natural Gas Storage Report
Working gas in storage was 3,248 Bcf as of Friday, December 13, 2013, according to EIA estimates. This represents a net decline of 285 Bcf from the previous week. Stocks were 488 Bcf less than last year at this time and 261 Bcf below the 5-year average of 3,509 Bcf. In the East Region, stocks were 207 Bcf below the 5-year average following net withdrawals of 132 Bcf. Stocks in the Producing Region were 23 Bcf below the 5-year average of 1,138 Bcf after a net withdrawal of 99 Bcf. Stocks in the West Region were 31 Bcf below the 5-year average after a net drawdown of 54 Bcf. At 3,248 Bcf, total working gas is within the 5-year historical range.
NYMEX Natural Gas Week-to-Week Price Change
Natural Gas Futures - Five Year Price
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