A few years ago, natural gas storage was one of the hottest segments of midstream infrastructure development. But along came shale, then oversupply, then depressed prices. The forward curve flattened out, killing off new storage development projects and putting a lot of financial pressure on those companies that own or lease storage capacity. But recently things have shifted, at least part of the way back to the good ole days. The summer/winter spread currently sits at $0.63/MMBtu (April 7, 2016), the highest level since 2012, and up significantly from the past years average of around $0.30/MMBtu. Midstream companies with available storage should be able to lock in higher prices compared to past years. In today’s blog, we look at the situation now facing natural gas storage operators and show how recent shifts in the market may affect their returns.
Before we go on, we need to point out that this blog addresses company level data. This analysis provides a context for our market assessment, and should not be viewed as investment advice. RBN is not an investment advisor, nor do we endorse the purchase or sale of any particular security or make any other market recommendations.
In February 2014 Boardwalk Pipeline Partners (BWP) stunned the market by slashing their distribution ~80% sending the units tumbling approximately 50% in a single day. In their conference call management cited the adverse market for natural gas storage and parking (short-term storage) as one of the main reasons for the distribution cut. Looking back into BWP’s financials confirms management’s comments. Storage and parking revenue declined approximately $40 million a year from 2013 to 2015. Average rates per Mcf of storage at BWP’s Bistineau storage facility were cut from $0.99 per year in 2010 to a paltry $0.15 in 2014. Boardwalk was not alone in feeling the pain from the weak storage market. Niska Gas Storage Partners, a pure play storage operator in North America, saw their units tumble approximately 90% at the end of 2014. Storage and optimization revenues for the company were down over 50% for fiscal year 2015 compared to 2014. Even more diversified midstream companies felt some of the pain. Crestwood, Spectra, Kinder Morgan, and many others have seen natural gas storage revenues fall significantly over the past few years.
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Valuing natural gas storage capacity can be a complex exercise. There are many variables that need to be considered such as regional prices, storage type (depleted reservoir, aquifer, salt), cyclability (maximum frequency of injections and withdrawals), competition, liquidity, contract length, and vintage (contract age). In addition, different storage users will value storage differently based on their needs and ultimate end use. There are a number of methods used to put a value on storage capacity. We will focus on the most simplistic of those methods, called intrinsic valuation (see I will Survive – Making Money with Natural Gas Storage in the Shale Era). In most competitive markets this is the largest driver of storage value and the intrinsic value this year is much improved over the last few years.
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Comments
Jim --
A great article and very timely. Thank you.
I noticed that you used examples from the South Central Region. Based on how full the South Central Region storage is at this point, and the amount injected into South Central Region storage last year, it looks to me like storage might be a bit cozy in the South Central Region: Like an extra 300-400 BCF over capacity cozy.
It also seems probable that the shortage of South Central Storage space may present itself sooner rather than later given the low demand during shoulder season and last year's injection rates in spring and early summer. Although South Central Region production may have declined a bit, it hasn't declined that much yet; I would also assume that those declines would likely be largely offset by flows from recently completed pipeline projects, e.g., the ANR SE Mainlin that brings Marcellus and Utica gas to the Gulf area.
I am also assuming that even if we have signficant declines in South Central Region production, the majority of those declines will be "back-loaded," i.e., the declines will start small and end larger, meaning there is relatively more gas to deal with early in the season.
This leads me to assume that there may not be sufficient space in the South Central Region for everyone who wants to store. Given the levels of production from the Marcellus and Utica, it would seem likely that little additional storage capacity will be available in the East Region. My guess as to the most likely scenario, therefore, would be that the excess production that can't be stored in the South Central Region would have to find a home in the Midwest. This would seem to entail not only additional transporation expenses, but also likely a certain amount of aquifer storage, given that is a chunk of what the Midwest has available, particularly closer to the South Central region.
As robust as $0.63 may seem compared to recent years, I'm wondering if the transportation costs and the less desireable features associated with aquifer storage will make that a loser for South Central gas that has to be shipped and stored in the Midwest.
Do you see problems with insufficient storage in the South Central Region causing some gas to have to be shipped elsewhere? Are there other likely alternatives besides the Midwest? Am I missing something that makes this seemingly significant problem not as serious as it appears??? What will this do the economics?? Will people be willing to sell gas in the South Central Region more cheaply so they do not have to pay to ship it elsewhere to store?
Also, I haven't seen much discussion of this issue, which seems odd to me. Any idea why?
Thanks again for the great info. I hope you can shed some light on the questions I have about the lack of storage capacity in the South Central Region.
Nice article, but still long article with a simple point. Nothing has changed with long term spread since 2011 and near term spread is good because of a glut, just like 2012.