Eight years into the Shale Revolution –– and two years into a crude oil price slump that put the brakes on production growth –– midstream companies continue to develop new pipelines to move crude to market. As always, the aims of these investments in new takeaway capacity may include reducing or eliminating delivery constraints, shrinking the price differentials that hurt producers in takeaway-constrained areas, or giving producers access to new markets or refineries access to new sources of supply. Whatever the economic rationale for developing new pipeline capacity, midstreamers and potential crude oil shippers need to examine–– early on –– the likely capital cost of possible projects, if only to help them determine which projects are worth pursuing, and which aren’t. Today, we begin a series on how midstream companies and potential shippers evaluate (and continually reassess) the rationale for new crude pipeline capacity in today’s topsy-turvy markets.
Posts from Rick Smead
It’s no secret that a long list of pipeline projects have been proposed to help move natural gas out of the Northeast production areas. But if you were a Marcellus or Utica producer, how would you decide whether you were interested in new capacity that hadn’t been proposed or built yet? Of course, pipeline companies have armies of engineers, cost estimators, and market analysts to bring one of these monster projects to fruition. But for anyone else, particularly in the early stages, how do you even know it’s a reasonable idea? For anyone testing a concept, you need a way to ballpark some scenarios for a new pipe. We’ve been running a blog series on our RBN Pipeline Economics Estimation Model, a quick, rule-of-thumb “sanity test” for new capacity. Today, we wrap up our walk-through of the model, with a real-world example to gauge the accuracy of the model, and then with a discussion on how the model can be used to measure economies of scale in picking the minimum volume you probably need for a new pipeline.
New and expansion natural gas pipeline projects have been part and parcel of the shale production boom in the U.S. Northeast. In fact, Northeast gas production could not have reached anywhere near its current level and become a major natural gas supplier to the U.S. without the substantial addition of takeaway capacity out of the Marcellus/Utica shale areas. At the same time, the competition among pipeline developers jockeying to be in the right place at the right time has been fierce. And now, low natural gas prices and uncertainty about future production growth have only increased the competition---not all projects will make it to in-service. The risks are higher for big pipeline projects, but so are the stakes. These days, the overall risk tolerance among shippers and investors is low, especially among producers. So if you’re a producer, how can you make sure you don’t end up on the wrong side of a transportation deal? In today’s blog, we continue our walk-through of the RBN Pipeline Economics Estimation Model. We’ll follow up in a later installment with a real-world test and other ways to use the model.
We’ve spent a lot of time here in the RBN blogosphere discussing the trials and tribulations of natural gas producers in the Marcellus and Utica shales who are “trapped behind the pipe,” unable to get sufficient takeaway capacity to move supply to market (both within and outside the U.S. Northeast region) where they could get a higher price for their gas. Pipeline companies have ponied up billions of dollars to build lots of pipe to alleviate these constraints and much more investment is planned. Of course, those pipelines and their committed shippers hope that the investment will pay off long-term – that the economics for building the pipe will justify the cost. The pipeline will have scores of engineers, lawyers and accountants to figure that out. But what if you just want to make a quick-and-dirty estimate of the economics? Well, there is a way. In today’s blog, we walk through the factors you need to consider when your boss runs in and asks, “Hey—what would it cost to move gas there in a new pipe?”
On Friday of last week, two more large E&Ps filed for Chapter 11 – Ultra petroleum with $3.8 billion in unsecured debt and Midstates Petroleum filing with a $2 billion debt-for-equity swap deal. Over the past 18 months there have been 65 E&P bankruptcies – mostly small companies, but nine companies make up 75% of the $28 billion in total debt exposure of all of these firms. This chaos in the oil, gas, and NGL markets is having all kinds of financial and strategic ramifications. One of the consequences of all of the turmoil could be a wave of asset sales, demands for contract restructuring, and more bankruptcy proceedings. But there can be some real opportunities in all this chaos if you know what to look for, understand where the needs and pitfalls can lie, and especially to recognize that “the sun’ll come up tomorrow.”
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.
It is certainly no secret that hydraulic fracturing, the process used to crack shale to yield natural gas and oil, is highly controversial. Numerous reports, claims, protests, etc. have asserted that hydraulic fracturing poses a danger to drinking water, which has led to a storm of argument and opposition in many areas of the country. Anyone wondering how oil and gas markets will work in the future must have in the back of their mind the possibility that opposition could lead to rules that would stifle supply development. So many were anxiously awaiting an Environmental Protection Agency (EPA) study of hydraulic fracturing and drinking water that had been going on for five years. The draft of that study was released in June. What does it do, and what does it mean for oil and gas future development? Today, we explore some of the findings of the draft report and focus on its implications for the natural gas industry.
Yesterday the Energy Information Administration (EIA) released their 2015 Annual Energy Outlook that forecasts U.S. demand for natural gas to increase by as much as 42% from 2014’s 26 TCF/year to 37 TCF/year by 2040. That translates to 101 BCF/d and is predicated on long term supplies of relatively cheap gas! Can the U.S. produce that much gas over the long term? Last week a group that is little known outside the natural gas industry – the Potential Gas Committee (PGC) provided an answer to that question when they announced their latest estimate of economically recoverable natural gas resources in the U.S. Today we analyze the impact of the latest PGC estimate and its long-term implications for the natural gas industry.
With U.S. natural gas production continuing to hit all-time records, the big question for the gas market is demand. Where is all that gas going to go? Well, we are pretty sure that most of the supply growth will be absorbed by the triad of new gas fired power generation, industrial demand and exports. The funny thing is that most of the volumes associated with these demand sources are located in one region – the southeastern U.S., with a heavy concentration of demand in Louisiana, home of the Henry Hub. This shift is turning what was a major supply area into an epicenter of natural gas demand, with the need for extensive new transportation paths into, rather than out of, the region. Today, we explore the implications of this transformation.
Power generation has surged as a market for natural gas in recent years, and gas-fired generation has become the largest single source of generation capacity. So coordinating the two industries, or “Gas-Electric Harmonization” has been around as an issue for quite some time. But while pipelines, generators, and shippers have been arguing about a host of complicated (and pretty boring) issues for about 20 years, the subject has really heated up lately, and has the potential to cause some maj
There is a common theme of surplus in US energy markets today with more natural gas, natural gas liquids (NGLs) and light sweet crude oil being produced than can be processed and consumed domestically. The likely destination of those surpluses is export markets – either directly or in the form of derivative products. How should we think about these exports in the context of “energy independence”? U.S. energy policy since the 1970s has been centered on the importance to national security of reducing dependence on foreign resources—the oft-touted, elusive goal of “energy independence.” Today we examine whether a btu energy balance is a practical and effective measure of energy independence.
Natural gas and oil development, especially in shale plays that require a lot of wells and a lot of activity, can be inconvenient and noisy. There are also, of course, various criticisms and protests around some of the processes used, such as hydraulic fracturing, and around the overall level of activity, such as truck traffic. The gas and oil producing industry values strong relationships with the communities where it needs to work, and can use all the friends it can get as it takes the lead in developing the nation’s vast energy resource. Bringing big economic benefits to those communities, which are often rural or industrial areas hard-hit by economic downturns, is clearly really important in the efforts to build those relationships and friendships. There are a lot of different kinds of economic benefits deriving from supply development, but by far the most important to the affected landowners are the royalties resulting from private mineral rights. Today we continue our examination of the inner workings of oil and mineral rights issues, this time considering some common oil and gas royalty disputes.
There has been a great deal of publicity around royalties involved with the shale gas—stories of instant millionaires (or “shaleionaires,” as 60 Minutes called them in 2010), stories of producers reducing or even eliminating some royalty payments as the vast oversupply of natural gas took hold in the last couple of years, stories of long, excruciating negotiations to reach a royalty/lease agreement, only to find out that the seller’s side of the table didn’t actually contain the owner of the rights, and stories of neighbors turning on each other when they got radically different deals based on timing or whom they were dealing with, and so on. Unless you have been directly involved in leasing and royalty work, a lot of it can be confusing. So today we begin a blog series to illuminate the world of mineral rights, oil & gas leases and royalties.
As we move into the Golden Years of U.S. natural gas, it is important to understand the long-term sustainability of such a large expansion to U.S. natural gas supplies and their uses. Our strong conclusion is that US natural gas supply will comfortably meet expected increases in demand in the years out to 2025. And that is important, because if the rapid expansion of demand, including hotly debated sectors like LNG exports, really did start putting strain on the nation’s gas supplies, prices could be higher going forward. But if sufficient confidence exists in the ability of producers to supply enough gas to meet plausible demand scenarios for a long time to come, then stable prices can be expected (and are), which will allow some industrial demand projects to actually get built. Today’s blog concludes our series on natural gas supply and demand.
The golden years of natural gas abundance are off and running, with export projects, new industrial proposals, new power generation use, and expanded transportation use - all building on a perception of long-term abundant supply at reasonable prices. Does it all work out in the end? Do supply and demand balance at stable, affordable prices, even with a lot more demand? Today we examine the likelihood that gas producers can provide adequate supplies without causing significant upward pressure on prices.