IRR

Cheniere Energy last Friday announced it has signed precedent agreements (firm capacity deals) with foundation shippers for its 1.4-Bcf/d Midship Pipeline project, which is targeted for an early 2019 in-service date. The announcement marks the latest milestone for midstream companies looking to move natural gas production from the SCOOP/STACK shale plays in central Oklahoma to growing demand markets in the Southeast and along the Texas Gulf Coast. Production from SCOOP and STACK grew by 1.0 Bcf/d, or 60%, in the past three years to 2.7 Bcf/d in 2016 and is expected to grow by another 1.5 Bcf/d by 2021. Besides Midship, there are other projects vying to move SCOOP/STACK gas to market. But how much capacity is really needed and by when? Today we look at the Midship project and its role in alleviating potential takeaway constraints.

The oil- and condensate-focused SCOOP and STACK shale plays in Central Oklahoma have been garnering the industry’s attention for their attractive producer economics, which are second only to the Permian among the crude oil shale plays. Rig additions in Oklahoma over the past several months are clearly targeting this 11-county area of the Anadarko Basin, and the RBN Production Economics Model projects production from the region will grow by 1.5 Bcf/d over the next five years. The increased drilling activity and expected production growth has piqued the interest of midstream companies looking to invest in infrastructure in the area. Given the increased output, is more takeaway capacity needed, and if so by when? Today we continue our look at the potential for takeaway constraints out of the SCOOP and STACK.

Natural gas production out of Oklahoma’s SCOOP and STACK plays has been resilient in the face of lower oil and gas prices and is expected to grow by about 1.5 Bcf/d over the next five years. But with the Marcellus/Utica increasingly competing for both pipeline capacity and demand markets outside the Northeast region, the question is where can and will the new SCOOP/STACK supply go? That will be dictated in large part by where demand is growing—primarily along the Gulf Coast—and where the price differentials are attractive. But flows also can be hindered or facilitated by another, preeminent factor:  pipeline takeaway capacity. Today we explore the potential for takeaway constraints out of the SCOOP and STACK.

Natural gas production from the oil- and condensate-focused SCOOP/STACK combo play in Oklahoma—one of the most productive plays in the U.S. currently—grew through 2016, even as other producing areas in the state, and in the Midcontinent as a whole, declined. As one of just a handful of locations that returning rigs are targeting, the SCOOP/STACK has the potential to single-handedly offset production declines in other parts of the U.S. Midcontinent and make Oklahoma a natural gas growth state again. Moreover, the RBN production economics model shows the natural gas output from the SCOOP/STACK has the numbers and the proximity to be directly competitive with gas supply from the Marcellus/Utica. Today, we continue our SCOOP/STACK series, with a look at the production economics driving interest in this play.

Many factors are weighed before a midstream company commits to building, or a shipper commits to shipping on, a major crude oil pipeline. Where is incremental pipeline capacity needed? What would be the logical origin and terminus for the pipeline? What should the project’s capacity be, and what would be the capital cost of building the project? Where the economic rubber really meets the road is the question of what unit cost––or rate per barrel––would the pipeline developer need to charge to recover its costs and earn a reasonable rate of return on its investment.  A really important aspect of that is what the developer will be allowed to charge, once regulators get into it.   Today we continue our review of crude oil pipeline economics with an overview of who regulates oil pipelines, how they do it, and what it means for rates.

In Part 1 of this series we discussed the fact that new pipeline development is driven by either need or opportunity, and more often than not, a combination of the two. The key question that pipeline developers and their customers (the shippers) have to consider before committing to build new capacity, we said, is whether it will “pay” to flow crude on the pipeline once it’s built––not just the first year or the first three, but for years if not decades to come. To answer this question, pipeline developers and shippers have to consider both current and future economics. There are three fundamental factors that drive pipeline economics: 1) future supply dynamics (and the resulting price impact) at the origination point (Point A); 2) future demand (and price) at the destination point (Point B); and 3) the transportation cost to flow crude from Point A to Point B.  

Many factors are weighed before a midstream company commits to building, or a shipper commits to shipping on, a major crude oil pipeline. Where is incremental pipeline capacity needed? What would be the logical origin and terminus for the pipeline? What should the project’s capacity be, and what would be the capital cost of building the project? Where the economic rubber really meets the road is the question of what unit cost––or rate per barrel––would the pipeline developer need to charge to recover its costs and earn a reasonable rate of return on its investment. Today we continue our review of crude oil pipeline economics with a look at the rules-of-thumb for determining what pipeline transportation rates would be.

The oil price collapse has opened a wide rift between high quality “good” assets, breakeven “bad” assets, and ruinous “ugly” assets.  The consequences will impact energy markets for decades to come.  In our recently published Drill Down Report, we demonstrate the differences between good, bad and ugly wells by examining the diversity of production economics across the Eagle Ford basin and why producers have been zeroing in on the counties——and areas within those counties—where initial production (IP) rates are highest, and preferably where large volumes of associated natural gas and natural gas liquids can be found as well. Today we consider Eagle Ford counties in more depth—their IPs, their internal rates of return (IRRs), and the number of new-well permit applications in each county in the first quarter of 2016.

The CME/NYMEX Henry Hub contract for January delivery hit a 17-year low yesterday (December 10, 2015) of $2.015/MMBtu, 46 % below year-ago price levels. But US gas production has been humming along near 73 Bcf/d, more than 3.0 Bcf above a year ago and about 1.0 Bcf below the all-time high earlier this year.  It’s a similar story for crude oil, with oil prices closing at $36.76/Bbl yesterday, but production hanging in there above 9 MMb/d.   This is a testament to lower drilling service costs and producers’ ability to improve drilling productivity. But can productivity gains and drilling costs keep up with continually lower commodity prices? Today we look at how productivity gains and falling drilling costs are impacting producers’ rates of return.

Producer rates of return are far below where they were a few months back, and the Baker Hughes crude rig count is down 553 since November. A third of pre-crash crude rigs are now idled. That means that crude oil production will be falling soon, right?  Not necessarily.  There are a number of factors working to keep production up, not the least of which is the rapidly declining cost for drilling and completion services.  Today we examine the impact of these factors, review RBN’s crude oil production scenarios and consider what it all means for the long-term relationships between prices, returns and production volumes.

On Friday (January 23, 2015) West Texas Intermediate (WTI) futures prices closed under $46/Bbl for the second time this year. RBN’s analysis of producer internal rates of return (IRRs) for typical oil wells indicates that Bakken IRRs have fallen from 39% in the fall of 2014 to just 1% today. IRRs for typical Permian wells are down to 3% and typical Eagle Ford wells are at breakeven. Everything is underwater or close to it except for the sweet spot wells with higher production. Today we present highlights from RBN’s IRR and breakeven analysis – published in full today in our latest Drill Down Report.