Six Key Factors Driving Gas and Electricity Prices

April 25, 2017

Natural gas (and subsequently electricity) prices are driven by the balance between supply and demand. When demand exceeds supply, prices go up, and vice-versa. As we move toward the 2017 summer season, there are six key factors that will drive supply/demand and determine gas and electricity prices going forward.

Demand Factors

Weather and cooling demand

Short-term natural gas (and electricity) prices are most impacted by weather. Heating demand in the winter and cooling demand in the summer always pressure prices upward compared to the spring and fall shoulder months. This past winter was one of the warmest since 1950 and nine of the ten warmest winters have been followed by a hot summer. The National Oceanic and Atmospheric Administration (NOAA) has issued a warm June-August forecast which predicts widespread above-normal temperatures throughout most of the nation. The current ten-year normal summer temperature is also near the eighth hottest summer since 1950. In short, a hot summer with above-normal cooling demand is currently most likely weather outlook.

Increasing power burn and industrial usage

Last year, led by higher demand in the electric power and industrial sectors, natural gas consumption increased to 27.5 trillion cubic feet (Tcf). Low gas prices are accelerating the rate at which coal-fired generating plants are converting to gas for power generation. In 2017, 13 gigawatts (GW) of natural gas-fired generating capacity is scheduled to come online in the United States, adding to total end-of-2016 natural gas-fired capacity of 431 GW.  Low prices are also increasing demand for natural gas in the industrial sector, where coal consumption fell 11% last year. If prices remain low, domestic demand for natural gas will continue to expand.

LNG and Mexican gas exports

In late 2017 and 2018, twelve new natural gas pipelines will double natural gas exports to Mexico, from 7 to 14 billion cubic feet (Bcf) /day. Driven by a massive conversion from oil-fired power plants to 1,990 megawatts of new gas-fired generation in Mexico, daily pipeline exports through August 2016 are 25% above the year-ago level and 85% above the five-year (2011–15) average level.

Due, in large part, to the development of shale gas in the US, domestic natural gas prices are 2-3 times lower than international gas prices. This has led to the construction of liquid natural gas (LNG) export terminals. The Sabine Pass and Cove Point terminals are now operational with three additional LNG export facilities under construction.  Over the next three years, incremental demand from LNG exports is expected to grow from 8.9 Bcf/day to 16.8 Bcf/day. Between Mexican and LNG exports, the US will become a net exporter of natural gas by 2018. The result will be rising domestic gas prices that are more aligned with international market prices.

Supply Factors


So far, the increase in operational gas drilling rigs from a low of 88 a year ago to 162 in April (an 84% increase) has not led to increased production. Over the past year, natural gas production declined 3.2% as low prices forced producers offline or out of business.  Currently there are over 5,500 drilled but uncompleted (DUC) wells standing idle. Most of the slack in natural gas production has been taken up by lower-cost shale gas from the prolific Marcellus/Utica basins. These basins, however, currently lack the pipeline infrastructure to move shale gas into other markets.

As of April, U.S. dry production has been range-bound between 69-71 Bcf/d for the entirety of 2017.  Production would need to ramp up to 73+ Bcf/d just to cover the current demand coming online. For supply and demand to fully balance at the current time, U.S. gas supplies would need to rise by 6 Bcf/d by the end of this year through a combination of higher U.S. gas production and Canadian gas imports.

Pipeline construction

Regional electricity prices, ranging from a low of $0.0350/kWh in Texas to over $0.1050/kWh in New England, are mainly influenced by the pipeline capacity available for moving natural gas to the point of power generation. Almost half of New England’s total generation in 2015 came from natural gas fueled resources.

Seven new pipelines, including Rover, NEXUS, and Atlantic Sunrise, are being built in 2018-2020 to move gas surplus from the Marcellus and Utica production basins into the Midwest, New England, and Canada. As these pipelines come online, gas prices in the Midwest and New England should decline while prices in Ohio and western Pennsylvania will rise. Overall, there are 13 pipeline projects in the eastern half of the country that have been delayed by regulatory barriers. It remains to be seen if FERC and the Trump administration will remove the red tape stalling the northeast pipeline projects. Currently, three of the five FERC Commissioners still need to be appointed by the White House for these projects to move forward.

Natural gas supply

National gas supply, tracked weekly by the Energy Information Administration (EIA), is a major driver of gas prices. Considerable surplus over the past year has resulted in historically low natural gas prices. Currently, inventories are 15% higher than the five-year average, providing sufficient overhang to keep gas prices around $3/MMBtu. With lagging production and building demand, however, it wouldn’t take much to draw down on this surplus and tighten demand/supply to the point that prices moved aggressively upward toward the $4 range.

Natural gas supply cycles are based on whether we are in an injection season (the shoulder months of spring and fall) or in a withdrawal season (November through March and the summer). This frequently results in large price swings based on whether supply levels are adequate (relative to the five-year average) going into the withdrawal seasons. Prices always spike higher in the winter/summer as heating and cooling demand pull down inventories. EIA currently forecasts natural gas supply will be only 1% above the five-year average next October. That provides a very thin margin of reserves if heating demand peaks next winter.