In the aftermath of the massive Winter Storm Uri in February of last year and its impact on the natural gas industry, there has been a blizzard of civil and regulatory litigation. Whether it’s someone not providing contracted gas supply, not taking expensive must-take gas supply, or saying “not that contract, but this contract” where there was a big difference in pricing between the two, lawyers are having a field day with the meaning of two words: force majeure. To what extent was one party to an agreement protected from being in breach of contract because their deal said some things could be force majeure, or beyond their control? The purchase and sale of natural gas at issue in these contracts is overwhelmingly done through a standard base contract produced by the North American Energy Standards Board, or NAESB (pronounced “Nays-be,” not “Nazz-be”). In today’s RBN blog, we discuss the standard contract used for the vast majority of natural gas supply deals in the U.S. and how its provisions relate to the issues raised by last February’s Deep Freeze.
Posts from Rick Smead
As nobody in Texas will soon forget, in February of this year freezing temperatures across the southern U.S. hammered energy markets and resulted in widespread and long-lasting blackouts across the Energy Reliability Council of Texas (ERCOT) power region. Life for many Texans came to a standstill for a week until power could be restored. The resulting economic damages have been estimated in the billions. Many people, rightfully, questioned how an energy-rich state like Texas could have been so affected. And then the blame-game started. Lacking a forum of qualified experts, productive discussions took a back seat to self-serving rhetoric, special-interest advocacy, and political posturing. But if real solutions were going to be found, it would take more than finger-pointing. It would take a meeting of experts whose primary focus was a resolution, rather than a constituency. Fortunately for Texans, that’s what they got two weeks ago. In today’s blog, we take you through the symposium and its outcome, particularly regarding the role of natural gas.
Oil and gas pipeline regulation have two things in common: They’re both regulated by the Federal Energy Regulatory Commission (FERC), and they were both brought under regulatory oversight in the first place by a Roosevelt — oil pipelines by Teddy Roosevelt and gas pipelines by Franklin Roosevelt. However, that’s where the similarities end. They’re regulated under different statutes, with wildly different histories that have led to very different types of oversight and rate structures. These rules tend to offer oil pipelines a higher degree of flexibility, but in doing so, they also make their rate structures less predictable. Today, we wrap up our review of oil and gas pipelines, and how their separate histories led to the current differences in pipeline rate structures, this time with a focus on oil pipeline ratemaking.
The uninitiated might be forgiven for thinking that oil and gas pipeline operations are similar. After all, they’re just long steel tubes that move hydrocarbons from one point to another, right? Well, that’s about where the similarity ends. While the oil and gas pipeline sectors are interlinked, they developed in quite distinctly different ways and that’s led to a vast chasm in both the way the two are regulated and how their transportation rates are determined. Bridging that gap between oil and gas can be a perilous and chaotic endeavor because you’ve got to consider how each sector evolved over time and the separate sets of rules that have been established to form today’s competitive marketplace. In today’s blog, we continue our review of oil and gas pipelines and how their separate histories led to the current differences in pipeline rate structures.
Here at RBN, we’ve built our analytics around the concept that hydrocarbon commodity markets — crude oil, natural gas, and NGLs — are fundamentally and closely linked. That’s why in all that we do, we emphasize that, in order to have an understanding of one market, you must also be competent in the others. That can be difficult at times when not only the market structure, but the very rules governing the upstream, midstream, and downstream sectors of oil and natural gas transportation are so different from each other. For example, consider the many contrasts between how oil and natural gas pipelines are regulated. Today, we look at how federal oversight of pipelines has evolved and why it matters for folks trying to move a barrel of crude oil or an Mcf of natural gas from Point A to Point B.
Just before the holidays, the Federal Regulatory Commission issued its final decision on the oil pipeline index rate for the next five years. The what?? Well, once rates for interstate oil pipelines are set and accepted by FERC, the rates can move around to match the market, but any increases are capped by an annual index announced by the FERC each year. The index is equal to the current year’s inflation rate, plus an “adder” that is calculated by the FERC every five years based on an examination of the industry’s results from the previous five years. In today’s blog, we explain how a few tweaks in the way FERC calculates the cost-of-service-based adder will significantly affect how much liquids pipeline rates can rise through the first half of the 2020s.
The U.S. natural gas pipeline sector is entering a challenging period for recontracting a major chunk of its capacity. The numerous pipeline systems built during the early years of the Shale Era’s midstream boom were anchored by 10-year, firm shipper contracts, mostly with producers, making them so-called “supply-push” pipelines. Many of those initial contract periods have begun to roll off, exposing pipelines to producer-shippers’ renewal decisions based on current fundamentals. Shippers typically expect substantially lower rates for a renewal contract, because much of the pipeline has been paid off through depreciation. But there’s another issue that is becoming more important: shipper recontracting may not happen for market reasons. For pipeline owners, this is happening at the worst possible time. The market is in turmoil and facing ongoing uncertainty. Gas production is down, demand from LNG export facilities is in flux, and regional supply-demand dynamics are shifting. As if that weren’t enough, new, large-diameter pipelines out of the Permian now nearing completion will reshuffle gas flows around the country. And other transportation corridors that not long ago were bursting at the seams and feverishly expanding to ease constraints are now at risk of being underutilized. Today, we discuss the factors that together may present significant risk for pipelines approaching the proverbial recontracting “cliff.”
On Thursday, June 18, the Federal Energy Regulatory Commission (FERC) issued a Notice of Inquiry (NOI) to reset the index that’s used to make annual changes to the rate ceilings for interstate pipelines that transport crude oil, refined products, and other hydrocarbon liquids. Every year, the highest rate an indexed oil pipeline can charge goes up or down — almost always up — using the FERC index. The commission’s new proposal, which would become effective in July 2021, follows an already-approved index adjustment that will take effect a week from Wednesday, on July 1. Taken together, the two changes would reduce the maximum annual increase in the rate ceiling from more than 4% now to less than 1%, which could have a major impact on liquids pipeline owners. Today, we discuss the NOI, the meaning of the pipeline index, where it came from, and where it might be headed.
The vast majority of the incremental natural gas pipeline capacity out of the Marcellus/Utica production area in recent years is designed to transport gas to either the Midwest, the Gulf Coast or the Southeast. Advancing these projects to construction and operation hasn’t always been easy, but generally speaking, most of the new pipelines and pipeline reversals have come online close to when their developers had planned. In contrast, efforts to build new gas pipelines into nearby New York State — a big market and the gateway to gas-starved New England — have hit one brick wall after another. At least until lately. In the past few weeks, one federal court ruling breathed new life into National Fuel Gas’s long-planned Northern Access Pipeline and another gave proponents of the proposed Constitution Pipeline hope that their project may finally be able to proceed. Today, we consider recent legal developments that may at long last enable new, New York-bound outlets for Marcellus/Utica gas to be built.
Back on March 15, the Federal Energy Regulatory Commission shook up master limited partnerships (MLPs) and their investors by deciding that income taxes would no longer be factored into the cost-of-service-based tariff rates of MLP-owned pipelines. We said then that there was no need to panic. In part, this was based on the view the FERC policy wouldn’t affect as much of the industry as some worried it would. But more importantly, our soothing message was tied to the fact it would take a long time for this to play out. It looks like we were right to have some confidence. Today, we explain why the commission’s July 18 vote on a topic as nerdy as “accumulated deferred income taxes” can warm the hearts of MLP investors.
There has been a lot of acrimony and polarization among the natural gas industry, the environmental community, various consumer advocates, industrial energy users, organized power markets and renewables developers in recent years. However, the ongoing government efforts to prop up the power sector’s coal-fired and nuclear generators have succeeded in uniting all those disparate interests into a single voice saying a single word: No! Today, we discuss the history of the administration’s planned support of coal and nuclear, the unusually unified reaction to it from groups that are more often at odds with each other, and some underlying assumptions about natural gas that aren’t — well — how the gas industry says it works.
Two months ago, the Federal Energy Regulatory Commission shook up master limited partnerships (MLPs) and their investors by deciding that income taxes would no longer be factored into the cost-based tariff rates of MLP-owned pipelines. We said then that there was no need to panic — that all this will take time to play out, and that the end results may not be as widespread or dire as some feared. Today, we provide an update, dig into FERC’s other actions on changes in income taxes, and discuss the phenomenon known as “FERC Time.”
The aftershocks are still being felt from last Thursday’s decision by the Federal Energy Regulatory Commission (FERC) that interstate gas and liquids pipelines’ cost-based tariff rates can’t include anything for income taxes if the pipelines are owned by master limited partnerships (MLPs) — and most are. Many investors did freak out — no other phrase sums it up better — when they heard that news. Share prices for midstream companies plummeted in midday trading, and we imagine that many angry calls were made by investors to their financial advisers. “Why didn’t we know about this?!” In fact, although this proceeding had been simmering for a while, FERC’s action was harsher than expected by most experts. But the impact of the change is likely to be less far-reaching than the Wall Street frenzy would have you believe, at least for most MLPs. And, by the way, the issue at hand — whether and how to factor in taxes in calculating MLPs’ cost-of-service-based rates for interstate pipelines –– has been around for decades. Today, we discuss FERC’s new policy statement on the treatment of income taxes and what it means for natural gas, crude oil, natural gas liquid (NGL) and refined product pipeline rates; and for investors in MLPs that own and operate the systems.
A federal appellate court decision has set back the approval of a newly completed set of natural gas pipelines in the U.S. Southeast, and raised the possibility that all gas pipeline projects will need to clear a new — and potentially challenging — hurdle before they can secure a final OK from the Federal Energy Regulatory Commission (FERC). In its late-August ruling in Sierra Club, et al vs. FERC, the U.S. Court of Appeals for the District of Columbia Circuit said FERC’s environmental impact statement for the Southeast Market Pipelines Project, which includes the 1.1-Bcf/d Sabal Trail pipeline from west-central Alabama to central Florida, should have considered greenhouse gas emissions from gas-fired power plants the new pipelines will serve. Today, we explore the potentially far-reaching effect of the decision on midstream companies and the utilities that depend on them.
On August 4, the U.S. Senate confirmed two new commissioners for the Federal Energy Regulatory Commission (FERC), restoring the three-member quorum legally required for FERC to vote. The Senate action ended a six-month dry spell during which FERC could not issue any orders, and thus could not approve any of the many pipeline projects pending there. What does it mean that FERC can act again to approve new projects? And does that mean the industry can move forward at the pace it needs? Today we explore these questions and assess what it will take to get some key gas infrastructure projects back on track.