summer

Texas and California are opposites in many ways, including their expectations for power prices in the summer ahead. Texas set single-day demand records several times last year and is anticipating more sizzling temperatures — and higher power prices — this year with demand expected to be near available supply. It’s the opposite for California, where the state’s extensive renewable buildout and higher-than-normal hydropower resources are helping keep a lid on power costs. In today’s RBN blog, we’ll examine the factors impacting Texas and California that are causing these polarizing power conditions. 

The Energy Information Administration (EIA) recently changed the weather forecast methodology for one of its most important energy models — the Short-Term Energy Outlook (STEO) — and while we talk about the effects of weather on energy markets fairly often (571 times in the past 12 years, or about once a week, but who’s counting?), we rarely take a step back and explain how those weather forecasts are used. In today’s RBN blog, we look at different approaches to weather forecasting, the recent change made by the EIA, and how the new approach might affect our understanding of EIA forecasts.

The U.S. gas market in April — the first month of the official storage injection season — was anything but typical. Production was at record highs, nearly 8.0 Bcf/d higher than last year. At the same time, weather in April was exceptionally cold, which meant storage activity remained in withdrawal mode on a net U.S. basis through the first three weeks of the month — a first for the April gas market going back at least eight years. That anomaly, in turn, led to an expanding deficit in storage compared to previous years, deferring the inevitable — shoulder season weather and supply surpluses — for another month. But now, in May, with the cold-weather effects on gas demand fading and record production levels here to stay, the market is bracing for a storage tsunami. The question is, will it be enough to erase the massive inventory deficit compared to recent years? Today, we update our analysis of the gas market balance and implications for the 2018 injection season.

The CME/NYMEX Henry Hub prompt natural gas futures contract last week settled at $3.213/MMBtu, the highest daily settlement since late May 2017. Despite natural gas production climbing nearly 3.0 Bcf/d over the past couple of months to record highs, the U.S. gas supply and demand balance has tightened considerably in recent weeks, particularly relative to last year at this time. Moreover, U.S. gas storage inventory has remained below year-ago levels and also moved below the five-year average level in recent weeks. That’s because gas demand has managed to more than offset the incremental supply in the market. How did that happen and what can it tell us about what to expect this winter? Today, we analyze recent shifts in gas market fundamentals.

At yesterday’s close (April 28, 2015) the CME NYMEX Henry Hub natural gas futures strip (average) for the nearby 12 months was $2.794/MMBtu.  That was only slightly above Monday’s three year low for the strip. The price weakness has been brought on by concern about a growing storage surplus. Last week the Energy Information Administration (EIA) last week reported that U.S. natural gas storage as of April 17 was 737 Bcf, or 83%, higher than this time last year. Within a year, the gas market has gone from the biggest storage deficit and lowest inventory since 2003 at the end of March 2014, to a massive year-over-year surplus and the possibility of a record-high inventory by the end of injection season. In today’s blog, we look at how inventories got here and implications for the summer gas market.

In the dead of the natural gas winter season when US producers count on strong margins from higher gas prices, the Transco Z6 New York hub is trading on average nearly flat  with U.S. benchmark Henry Hub, LA – the delivery point for the CME NYMEX natural gas futures contract. This is a dramatic departure from historical winter norms in the Northeast market, where prices relative to Henry and just about every other gas hub in the Northeast have traditionally carried hefty premiums in the winter. Moreover, the forward curves indicate these basis levels are the new norm for Northeast pricing. The forward curve for Transco Z6 New York shows basis for 2015 barely above Henry Hub for the year, with several months at more than $1.00/MMBtu discount. Today we look at what’s behind major changes in northeast forward curves.

We enter the natural gas winter this November after a record-breaking storage season that saw 2.75 Tcf of summer surplus squirreled away into underground storage. That surplus resulted from record breaking U.S. production exceeding lower summer demand. This year a repeat of last year’s freezing winter should run down storage enough to leave room for another summer of surplus. But with U.S. production at 70 Bcf/d and northeast output up 22 percent this year to nearly 18 Bcf/d gas supplies have reached a level where anything but a cold winter will leave too much gas in the ground next March. That theoretically would leave no room to inject surplus supplies into storage next summer – threatening the balancing role that storage plays in the natural gas market. Today we explain how the gas supply demand balance is threatened by changes to the storage market.

From a high of $6.14/MMBtu in February 2014 natural gas prices have fallen to $4.013/MMBtu yesterday (September 17, 2014). In large part the price decline reflects the recovery of gas storage levels from record lows in March at the end of a freezing winter. Booming production and a milder summer have provided the surplus supplies needed for injections to replenish inventories reasonably close to normal levels (the latest storage numbers are released by the Energy Information Administration (EIA) this morning (September 18, 2014). Today we describe the impact of supply and weather driven demand on storage levels.

Recent seasonal averages on the CME NYMEX Henry Hub natural gas forward curve show just an 8 cents/MMBtu spread between next winter (2014/2015) and this summer (2014) – a number that provides very little incentive for storage injection. Things don’t look much better for storage spreads further out on the curve either with an average spread over the next 10 years of just 33 cents/MMBtu. Today we analyze storage spreads over the past 6 years.

Several key factors point to a gradual increase in natural gas power burn over the next few years. More gas-fired units are coming online, and more coal-units are being retired.   But with gas prices trending higher this spring and summer than in the same periods last year, 2014 gas use by the electric sector may end up unchanged from 2013--unless this summer is a scorcher. The stronger pricing is good news for producers, of course, as is the very real need to replenish depleted gas stocks. Today, in the first episode of a new series on power burn demand for natural gas, we look back at 2013 and forward to prospects for 2014