Twenty Questions About Natural Gas Performance During Winter 2013-2014
Overview: Natural gas market conditions during this winter of extreme, widespread and sustained cold show that the system was challenged more than ever before in history — but it performed reliably despite record cold and record consumption.
- What factor has the greatest influence on natural gas prices?
- How did this past winter’s weather compare to previous cold winters?
- What was the impact on natural gas consumption?
- What was the impact on natural gas prices and how did prices compare to previous cold winters?
- Was natural gas production affected by the cold weather?
- What are “freeze-offs?”
- How did freeze-offs impact natural gas supply this winter?
- Could customers get natural gas?
- What is the difference between “interruptible” and “firm” transportation?
- Why do some customers choose to be interruptible?
- What is the difference between “spot” prices, “wellhead” prices and other kinds of natural gas prices?
- Why do electric generators buy so much natural gas from the spot market rather than through firm service or monthly contracts?
- What role did storage play in meeting demand this winter?
- Why are prices so different among different regions?
- Were all the winter issues due to increased demand or were there actual physical/operational problems as well?
- If there were so few true winter operational issues, why did we hear about many natural gas-fired power plants in PJM, ISO-New England and Midcontinent ISO that experienced “forced outages?”
- What drove New England’s natural gas prices higher than other regions?
- Why haven’t more pipelines been built to New England?
- What can be done in New England to incent new pipelines?
- How can customers protect themselves against higher prices?
Without doubt, the biggest single short-term influence on natural gas supply and demand – and thus prices – is weather.
Winter is the peak consumption period for natural gas. The colder it is, the more natural gas is needed for space heating for homes and businesses, and also for power plants that use natural gas to generate electricity. In response to competitive market prices for natural gas and in order to achieve cleaner emissions goals, power plants are increasingly turning to gas during hot months, so natural gas consumption also increases in the hot summer months.
Just as weather influences demand for natural gas, it also affects supply. Although we are focusing here on natural gas, weather impacts virtually all forms of energy in various ways. [return to questions]
It was one of the two coldest winters recorded in the last quarter-century. Record-setting cold temperatures were so widespread that two-thirds of the U.S. experienced historic demand levels nearly simultaneously in January. February and March were also significantly colder than normal in the Midwest and the East.
Unusual cold dominated the eastern two-thirds of the U.S. and nine states had a top 10 cold January.
In those regions, temperatures were 20 to 40 degrees below normal in January, which is 25 to 30 percent below normal.
Snowfall from Ohio through New England was two to three times normal during the winter.
There were at least four distinct spells of extreme widespread cold in January and February — dubbed the Polar Vortex, Son of Polar Vortex, Arctic Blast, Deep Freeze and so forth.
Colder-than-normal weather started quite early in October, which created increased demand for natural gas early in the heating season. [return to questions]
Natural gas consumption reached its highest level ever in January, even topping 137 Bcf/day for the first time in history on January 7th. Despite the extreme conditions and with only a few days notice, natural gas producers and suppliers were able to meet demand, a testament to the flexibility and efficiency of the natural gas system. [Source: Federal Energy Regulatory Committee report on winter operations and market performance, April 1, 2014]
- Deliveries to residential (33.6 Bcf/d), commercial (18.5 Bcf/d) and industrial (23.4 Bcf/d) customers each were the largest ever reported. [Source: EIA Monthly Gas Report, released March 31 2014]
- Consumption of natural gas set all-time records in January – including the highest month, highest week and the seven highest single days. On January 7th, consumption exceeded 137 Bcf, (FERC, EIA) the equivalent of supplying the entire U.S. twice-over on an average day. (Go to #5 to see how we met demand.) [return to questions]
Natural gas prices increased to a five-year high in February — but still peaked at only half of what customers paid in previous, pre-shale cold winters. [Source: EIA]
Highest daily Henry Hub spot price:
Peak in Feb. 2003 — Henry Hub peak of $18.48/MMBtu
Peak in Feb. 2014 — Henry Hub peak of $8.15/MMBtu
In 2014 — at the Henry Hub, natural gas prices peaked at $5.66 on January 27th. In February, Henry Hub prices stayed between $4.50 and $6.50 on all but four days, peaking at $8.15.
In comparison, during a one-week cold spell in February of 2003, Henry Hub prices varied between $8.42 and $18.48 [Source: EIA]. And the cold weather in February 2003 was not as cold as the winter we’ve just experienced.
The market moderated so quickly in 2014 compared to the extremes of most recent previous cold winter of 2003 because of the abundance of natural gas supply in the era of shale gas. [return to questions]
EIA data shows that production in January was at a record high, [Source: EIA] even though the unprecedented arctic blasts caused rare natural gas well freeze-offs in some areas. [Source: Bentek/Platts]
In fact, February 2014 production was 2.5 percent greater than the same month in 2013 and Jan/Feb 2014 production was 2.2 percent greater than the same period of time in 2013, despite the freeze-offs. [Source: EIA] [return to questions]
Very cold temperatures can sometimes cause natural gas wells to experience “freeze-offs,” when small amounts of water produced along with natural gas crystallize inside the pipelines at or near production wells, blocking off the gas flow and temporarily hindering production. Producers can address freeze-offs in several ways including adding insulation; applying external heat; or simply waiting for the weather to warm. Historically, freeze-offs occur when regions with typically mild weather experience unusual cold. [return to questions]
This past winter, freeze-offs occurred in nearly every region because of the severity of the cold. However, their overall impact on supply was small, since producers were able to manage the freeze-offs and kept them short in duration. Most lasted less than a day. [Source: Bentek]
- Freeze-offs occurred in nearly every region this winter, but were short, usually lasting less than a day and impacting less than 1 percent (0.6%) of total production. [Source: Bentek]
- Totaled 132 Bcf or a little more than 1 Bcf/day on average from Dec. 1, 2013-late March, 2014. [Source: Bentek/Platts Gas Daily, March 31, 2014]
- Despite freeze-offs, daily winter gas production exceeded last year by more than 2 percent. [Source: Bentek, EIA]
- Feb. 2014 production (65.7 Bcf/day) was 2.5 percent greater than February 2013.
- Year-to-date production was 2.2 percent greater than same period 2013.
- Production growth attributed to Marcellus Shale – even though the Marcellus experienced a cumulative 21 Bcf in freeze-offs for the winter. [return to questions]
Yes, customers could get natural gas at contracted levels. However customers have tremendous flexibility in how they choose to purchase their natural gas as well as the pipeline transportation needed to deliver it, and those choices mattered this winter.
If customers decided to wait to buy natural gas until a few hours before it was needed during the deep freeze, the gas was priced higher than natural gas purchased by contract with a supplier in advance. (See question #11 for a detailed explanation of the difference between natural gas purchased by contract in advance and gas purchased at the last minute on the daily “spot” or “cash” market.)
Customers also must purchase space (“capacity”) on the pipeline to ensure their spot market or contracted-for gas can be delivered. In general, customers decide whether to purchase their pipeline transportation capacity on either a “firm” or an “interruptible” basis. (See question #9 for explanation of firm and interruptible transportation.) [return to questions]
“Firm” transportation customers got their gas at contracted levels from pipelines, even though several all-time records for natural gas consumption were set as a result of record-setting cold.
Some “interruptible” transportation was indeed interrupted, as would be expected during periods of high demand.
According to testimony by the Interstate Natural Gas Association of America (INGAA), with extremely few short-term exceptions, there were no service disruptions or curtailments for natural gas pipeline customers that had contracted for reliable, firm service. [Source: INGAA testimony, March 6, 2014] [return to questions]
Businesses that can accommodate occasionally having their natural gas supply interrupted or that can significantly reduce their consumption when notified by the provider can get better rates for natural gas transportation by having “interruptible” service. Typically an interruptible customer is a large industrial or commercial customer with the ability to use other fuels or temporarily halt operations. In many regions, power generators choose to have interruptible transportation service for natural gas.
Interruptible customers that are located “behind the citygate,” meaning they are served by local utility pipelines, are usually required by the state to have the capability to switch to an alternative option or fuel when service is interrupted. In general, interruptible transportation is interrupted only when there is very high demand for gas by “firm” customers, usually only on the coldest days of the year.
“Firm” customers cannot have transportation service interrupted, even during periods of peak demand. Local gas utilities contract for firm service because they serve homes and businesses that cannot handle interruptions. [return to questions]
Customers like the cost savings that accompany interruptible transportation service. [return to questions]
Wellhead prices and citygate prices refer to the price paid at a physical point of sale.
- The “wellhead” price is the wholesale price of natural gas at its point of production. Factors that influence the wellhead price are supply and demand factors in the competitive marketplace, such as the weather, the availability of competing fuels (primarily coal and oil), overall gas demand and competition among customers for the available supplies. It does not include transportation costs of moving the gas away from producing wells.
- The “citygate” price is the sales price at the point where natural gas is transferred from an interstate or intrastate pipeline to a local natural gas utility. The citygate price includes the wholesale/wellhead price of natural gas as well as the cost of transporting it by pipeline to the citygate. In addition, citygate prices reflect local weather trends and usage patterns, the region where the natural gas supply originated, the number of competing interstate pipelines serving each region, and the availability of capacity on those pipelines.
“Spot” (also called “cash”) prices, futures prices, and short- and long-term contract prices refer to the expected term of delivery of the natural gas. Ideally, customers try to diversify their natural gas supply portfolios with a mix of gas from different supply regions acquired under different circumstances including spot market gas, short-term and longer-term contract gas, supplemented with gas from storage and peaking gas arrangements.
- Spot price – also known as the “cash” price – is the price paid for the natural gas in the “spot” market, where gas is purchased on a just-in-time basis. The spot or cash market is for gas that is needed rapidly and it enables customers to quickly respond to changes in weather or market conditions.There are numerous spot market trading hubs around the country, but the daily cash price at the Henry Hub spot market in Erath, Louisiana is the price most frequently quoted. Henry Hub traditionally is used as a national benchmark, because it interconnects numerous pipelines and is considered one of the more liquid natural gas trading locations.
- Natural gas delivery contracts that have terms of one year or less for actual physical delivery of gas are considered “short-term” contracts. Most short-term contracts have one- to six-month terms. An example of a typical transaction might involve a supplier striking a deal with a local natural gas utility that it will provide gas for a four-month period during the winter. Customers often enter into numerous short-term contracts with different suppliers for different delivery dates in order to ensure a reliable supply of natural gas at competitive rates.
- A small amount of natural gas that customers use, almost always during the winter heating season, is contracted for under “long-term contracts” – contracts with an obligation to deliver gas for a period of more than one year.
- Finally, there is the futures price of natural gas. The CME/New York Mercantile Exchange (NYMEX) allows the sale of natural gas contracts for future delivery made under NYMEX rules. A natural gas futures contract typically is a financial tool used by buyers and sellers of natural gas to minimize risk. Most of the natural gas transactions on the futures market do not involve the actual physical delivery of natural gas, although futures contracts that go to settlement will ultimately go to delivery as well. Typically however, natural gas futures contracts are financially resolved. The delivery site for futures contracts is the Henry Hub. [return to questions]
Power companies often buy natural gas to fuel power plants on a need-to-have-it basis in the spot market, counting on the fact that there will be enough natural gas available. There are no commercially viable ways to store electricity and competitive generators don’t want to buy more fuel than they will need. As addressed in question 18, competitive power markets are struggling with ways to incent generators to make purchasing decisions to ensure pre-arranged fuel supply in markets with seasonal pipeline transportation constraints. [return to questions]
The United States is somewhat unique in its ability to store natural gas for an indefinite period of time in underground storage facilities such as depleted gas reservoirs or salt domes. These storage facilities can be located near market centers that do not have a ready supply of locally produced natural gas. Because storage requires specific physical geological conditions, some regions of the U.S. have significantly more storage capacity than others. There is very little storage capacity in New England or the southeastern United States, for example. [see EIA map of U.S. storage facilities]
Storage enhances physical reliability by offering another ready source of gas supply. It also helps customers to manage their costs, since gas is usually purchased for storage when it is in least demand and thus at its lowest price in April through October. Storage is an important part of the winter supply portfolio.
Withdrawals from storage set a new record this past winter when a total of more than 2,800 billion cubic feet (Bcf) of gas was withdrawn over the winter heating season. To put that number in context, EIA estimates that total storage capacity is currently 4.7 Tcf.
- This winter heating season, 29 percent of natural gas consumed came from storage. In contrast, in a typical winter, 15-20 percent of overall winter consumption comes from storage gas. [Source: AGA Natural Gas Market Indicators, Feb. 28, 2014]
- Four weekly withdrawals were between 250 and 290 Bcf — numbers usually only seen once – at most — in a single winter. [Source: EIA Today in Energy, March 14, 2014]
- Storage capacity has grown by 20 percent since 2007 and is still growing, with six facilities currently under construction, expected to bring another 64 Bcf of new capacity online by 2016. [Source: EIA Today in Energy, March 14, 2014]
- The current total estimated Lower-48 working gas storage capacity is 4.7 Tcf. [Source: EIA Today in Energy, March 14, 2014] [return to questions]
In general, the average price of natural gas has decreased significantly across the U.S. since the arrival of abundant shale gas in the market. However there are regional variations.
In New England, the daily spot/cash market price for natural gas this winter increased more than in other regions, because of a lack of available pipeline capacity compared to other regions. However even in capacity-constrained New England, local gas utilities and other customers who had purchased their supply through term contracts (rather than on the spot/cash market) paid prices that were close to Henry Hub prices, at the time $4.50-$5.50/MMBtu. In contrast, daily cash/spot market prices in New England reached as high as $75.48 (Jan. 22nd) as customers competed for fuel supply to be delivered on the region’s constrained pipeline systems. [See question #18, Why aren’t more pipelines built to New England?] [Source: EIA Natural Gas Spot Prices] [return to questions]
15. Were all the winter issues due to increased demand or were there actual physical/operational problems as well?
There were very limited mechanical difficulties that were restricted to a day or so, primarily when two or three compressor units along the pipeline system failed due to cold weather. [Source: INGAA testimony, March 6, 2014]
- Example of disruption: On January 7, there was a compressor failure near Pittsburgh, Penna. on the Texas Eastern Pipeline system, which lasted for approximately 14 hours and resulted in across-the-board reduction of gas nominations on pipeline deliveries downstream of that compressor. [return to questions]
Nearly all of the forced outages of natural gas-fired generators occurred because those generators held interruptible contracts for natural gas. [Addressed in detail in questions 9, 10 and 12] Because of the cold weather, pipelines already were running at peak capacity with gas for local gas utilities, which held firm transportation contracts for their gas. [Source: PJM Analysis of Operational Events and Market Impacts During the January 2014 Cold Weather Events, May 8, 2014] [return to questions]
Largely because there’s not enough capacity into the region on the existing natural gas pipelines to satisfy peak demand on winter’s coldest days and competition was fierce for the natural gas that was available, including shipments of liquefied natural gas (LNG). Investment in new infrastructure is needed to deliver more natural gas to New England.
- In January, spot prices at New England’s main price point hub (Algonquin) ranged from mid-$4’s to $75.48/MMBtu. [Source: Platts] It is important to remember that only a portion of daily supply was secured at this price: the majority of supply was purchased at the hedged $4-$5 price.
- In February, spot prices steadied out, ranging from mid $10s to $31.98/MMBtu.[Source: Platts] [return to questions]
Actually, some pipeline expansion projects are underway and these will help the supply situation somewhat. However most experts agree that these pipeline expansions are not enough to meet the unique gas demands of power generators during peak periods in New England because most of the expansions don’t yet extend north of the New York area. More pipeline capacity will need to be built, along with more utilization of LNG to meet peak day demand.
Although pipeline capacity to the region is highly constrained, other market pressures make electric generators in ISO-New England reluctant to commit to the kind of long-term arrangement that pipeline companies need in order to build. In a nutshell, pipelines typically require potential shippers to commit to a long-term agreement to the pipeline so that pipelines have solid financial commitments before they move ahead to build a project. Historically, this arrangement has worked well for pipelines and their shippers including natural gas utilities, industrial customers and traditional electric utilities.
However, in ISO-New England, electric generators lack certainty about how often they will be dispatched and are reluctant to commit to such a long-term arrangement, fearing they will not be able to recoup its costs. Generators further fear that investment in securing reliable gas transportation will place them at an economic disadvantage to competitors in the energy bidding process. [return to questions]
Numerous groups are engaged in finding a way to incent new infrastructure in the region, including the states and their governors, ISO-New England, electric and gas stakeholders and FERC.
Stakeholders throughout the region are exploring solutions. Recently, the governors in New England announced an intention to work with ISO-NE to explore the idea of state-funded expansions.
- ISO-New England has asked FERC to approve a proposed “Pay For Performance” plan that would provide an incentive for generators to invest in reliability measures (e.g. dual-fuel capabilities, LNG options, and perhaps firm pipeline contracts). This proposal is a “start” to change market behaviors but more must be done to get pipelines built in the near-term. [return to questions]
This winter underscored the importance of customers using risk management tools and strategies so that they can acquire a diverse and stable natural gas supply portfolio. As addressed in questions 12 and 14, spot market prices only represent a small percentage of the overall volumes of natural gas being bought and/or sold for customers.
Customers including electric utilities and local natural gas utilities can use risk management tools and strategies to minimize risk to consumers, for example they can:
- Purchase natural gas from a variety of supply regions and sources including LNG, storage and peaking options.
- Use different types of contractual arrangements including a balance of daily spot market, short term contracts and long term contracts
- Use available financial hedging tools
Creating a diverse supply portfolio helps mitigate consumers exposure to daily market price volatility.
As addressed in question #18, competitive power suppliers (also known as merchant generators) operate under different power market structures and tend to buy a greater percentage of their natural gas on the daily spot market than their electric utility-owned competitors. Such contracting practices can put merchant power plants at a greater exposure to daily market volatility and supply constraints.
In contrast to electric utilities, local natural gas utilities have more predictable demand for natural gas and thus rely less on the daily spot market and frequently secure their natural gas supply under a variety of contract terms and from different supply regions and suppliers. They also take advantage of natural gas storage and some local gas utilities draw on other supplies for their peak demand days, such as on-system liquefied natural gas (LNG). [return to questions]