Within and near the Marcellus and Utica shale plays, power plant developers are building more than a dozen new natural gas-fired generating units, mostly combined-cycle plants that can operate essentially around-the-clock. This construction boom, spurred by a combination of abundant, low-cost gas and the regulation-driven retirement of scores of older coal plants, is boosting gas consumption close to gas production areas and reducing—at least a bit—the surplus gas volumes that Marcellus and Utica producers and marketers need to move to markets outside the region. Today, we examine the race to build new power plants near production areas in the Northeast, and consider what the resulting local gas consumption might mean for the region’s gas prices and pipeline needs.

It used to be the case that if natural gas even came up in power-industry discussions of generation, it  happened at the end of a meeting—“Well, we’re done with our nuclear and coal plans, anyone have anything else to discuss before we go to dinner?  Oh, that’s right—anything happening with gas?”  Now it’s the other way around.  It seems like every discussion starts with gas, whether it’s about the plants being low-cost and easy to site, about concerns around reliability and price volatility, or around the impact of the gas market on coal investments.  And power is clearly the fastest growing segment of the U.S. natural gas market.  But does all this attention from the power market mean that the natural gas industry really understands the power side?  Perhaps not.  In fact, we’ve found that frequently, as soon as we get beyond the marketers and analysts who deal specifically with supplying gas-fired power generation, there’s a lot the natural gas industry (and the energy markets in general) can learn about power plants, electricity markets, and how natural gas fits in.  So for that reason, we’ve concluded that now is a good time for a primer on how gas-fired generation works, how it fits together with energy markets and how it might be affected by national policy changes.   Today we take on this challenge with the first installment of a three-part series.

Natural gas prices for the nearby CME NYMEX futures contract at the Henry Hub in Louisiana have fallen by 38 percent from their high in February of $6.149/MMBtu to yesterday’s close at $3.847/MMBtu (July 24, 2014). Over the same period the price of CME NYMEX Appalachian coal has stayed virtually flat at $60/ton. So far falling gas prices have not increased power burn – the consumption of natural gas by power generators switching from coal. But natural gas prices in the Marcellus at Dominion South Point have fallen by nearly 60 percent since February to $2.46/MMBtu making natural gas a cheaper fuel than coal for power burn in that region. Today we discuss prospects for coal to gas switching this summer.

There is still a lot of summer left in Texas. Some say summer in the Lone Star state runs from Cinco de Mayo through the middle of the high school football season, which sounds about right. But so far at least, a combination of moderate electricity demand and relatively high natural gas prices has resulted in a decidedly non-stellar gas power burn. That is good news for those eager to see the state’s—and the nation’s—gas storage levels rebound from unusually low levels after the hard, cold winter of 2013-14. In this episode of our region-by-region series on gas power burn vs. gas storage rebuilding, we look at the Electric Reliability Council of Texas region, where gas-fired generation is king.

The “polar vortex” of 2014 dipped far south enough to impact power markets in Texas. On Monday January 6th, the Electric Reliability Council of Texas (ERCOT) came dangerously close to initiating rolling blackouts as power demand increased due to record low temperatures and unexpected generation unit outages. Real time electricity prices spiked to over $5,000/ Megawatt Hour (MWH). The close call served as a sobering reminder for Texas regulators of the ongoing debate over how the State will meet future power generation requirements. Today we detail the “polar vortex” event and explain the implications for Texas power. 

The golden years of natural gas abundance in which we find ourselves are sparking tremendous enthusiasm among potential users of the fuel, from power generators to major industrial companies, to exporters both current and potential.  After all, a trifecta of cheap, abundant, and clean is hard to resist.  But the big question is  how supply and demand really shake out after everyone’s enthusiasm results in new and growing use of the resource.  Is the natural gas industry going to be able to supply all the new demand without prices going up the way they have in the past, most recently hitting double-digits at Henry Hub just five years ago?  The first step in order to weigh supply against demand is to have a plausible scenario of what that demand might be. What does it all add up to?  So in today’s blog we will see how much demand we should be trying to meet, to be followed later by a next installment to see how producers might meet it.

Last year natural gas power burn increased by 6 Bcf/d over 2011. This year power burn levels in the first quarter were down 10 percent from 2012. Peabody Energy reported last week that coal consumption for generation is growing this year versus 2012. Today we ask whether 2012 power burn was an anomaly and what we should expect in 2013.

Does lightning strike twice?  How about three times?  Sure seems like the coal industry has been hit by three lightning bolts in the past several years: a recession that reduced demand for electrical power, low prices for competing fuels (i.e., natural gas), and new federal regulations on smokestack emissions.  Today we review regulations that have left coal power generators singing the smokestack blues.

Growth in natural gas demand forecasts these days rely heavily on projections of increased power burn. Lack of coordination between the gas and electric industries threatens to limit that expansion. The greatest challenge is the security of gas supply to the generators and how that impacts reliability. Regional differences in the electric power market appear to make national regulations to secure gas supplies unworkable. Today we review FERC efforts to understand and perhaps attempt to standardize those regional differences.

During 2012 the FERC jumped into the ring to involve itself in the long running debate to improve coordination between the gas and electric power industries. The FERC is motivated by concerns about reliability and the trend to increase power generation from natural gas at the expense of coal and oil. The commission held 5 regional conferences to identify the industry’s concerns and the role of regulation in any solutions. Today we examine progress on this important initiative.

Nowadays everyone is pretty sure that there is plenty of natural gas supply to go around. Storage is bursting at the seams; production is close to record levels. Midstream infrastructure companies are busy developing new pipelines and additions to deliver shale gas to existing markets. Market analysts agree that new natural gas demand over the next decade will largely come from increased gas fired power generation. Is the current natural gas infrastructure configured to deliver gas to this new generation capacity? Today we report on emerging power industry planning concerns.

Today the Energy Information Administration (EIA) publishes weekly US natural gas storage numbers for the week ending July 6, 2012. Last week EIA reported 39 Bcf injections making the total storage 3,102 Bcf. The natural gas stockpile is now 602 Bcf higher than this time last year but the rate of storage injection has slowed as a result of increased demand for natural gas burn by power generators. In today’s blog we look at the supply demand picture to see what is driving higher natural gas burn by power generators and the implications for storage.