May 10, 2018 | Warren Waite
There have been numerous stories in the news lately about the lack of takeaway capacity for Permian oil and gas producers to move their products out of the basin and the consequences it is having on regional prices. In March, OPIS PointLogic touched on this when we published The Mighty Permian – Growth and Potential Constraints in 2018-19.
In this edition of Get the Point, we’ll briefly review the oil and gas location differentials (basis) for West Texas Intermediate (WTI) crude and regional natural gas prices, but the focus will be on stacking Permian natural gas production against OPIS PointLogic modeled gas outflows away from the Permian. This becomes tricky since a large portion of the exit routes reside on Texas intrastate gas pipelines, which are not mandated to report flow activity. What happens if future production growth rates go unchecked and effective outflow capacity from the Permian is breached? We will walk through all the ins and outs of how gas can realistically leave the Permian and how future expansion projects stack up against potential production growth.
The information in this report is a high-level summary preview of what is included in OPIS PointLogic’s latest regional report. This report will be published both daily and weekly and include not only high level summary information that simplifies the complex, but the granular details to help provided market intelligence you can’t find elsewhere.
Debuting soon, this new regional report will span from the Permian and Texas to all the intricate markets within the Southeast. To find out more, contact email@example.com.
First, let’s begin with a quick recap from a few months ago.
The Permian has undoubtedly the best economics of any play in the Lower 48, with over half of the wells breaking even below $45/bbl. Current WTI crude oil prices at Cushing, Okla. are hovering near $70/bbl and have been above $60/bbl since the start of 2018.
However, Permian producers capture a WTI Midland, Texas price and the spread to a major downstream market price hub, Magellan East Houston, has become increasingly negative. The Energy Information Administration’s (EIA) Short-Term Energy Outlook from April noted how WTI-Midland was nearly $9/bbl discounted to Magellan East Houston in early April (see chart below), reflective of the oil takeaway dilemmas, whether it is pipe, rail or truck. Since then, the discount has widened even further. We’ll highlight Permian gas prices a little later.
Permian rig counts have been increasing steadily since 2017, with new wells being drilled much faster than well completions, which has led to a build-up of a significant inventory of drilled but uncompleted wells (DUCs). The big oil producers in the Permian expect 22%-45% overall production growth from 4Q2017 to 4Q2018 on a barrel of oil-equivalent (Boe) basis as they focus on scaling their acreage to maximize recoveries.
But it's "too much of a good thing," as producers are facing challenges in moving that gas to market. While oil and gas pipeline takeaway additions are planned, it is not until late 2018 and into 2019 before serious relief comes to fruition—assuming pipeline projects are not delayed.
Too Much of a Good Thing
Dry gas production growth in the Permian has effectively doubled since 2013, averaging nearly 7 Bcf/d in 2018. While this growth is impressive, it is important to remember where within the Permian this growth has been occurring. Since 2013, the Delaware Basin is up 1.5 Bcf/d and the Midland Basin has increased by 1.2 Bcf/d. Sandwiched in between those is the Central Basin, which has remained more or less flat. The New Mexico share of the Permian has increased by roughly 0.8 Bcf/d over the same period.
OPIS PointLogic’s modeled dry gas values accurately account for the evolving profile of hydrocarbons coming out of the wellhead in addition to various reductions that wet gas production endures prior to entering the pipeline grid. This phenomenon is explained in detail in a prior Get the Point, Downsized: The Incredible, True Story of Shrinking Texas Production.
Not all areas of the Permian have the same access or connectivity to gas pipelines leaving the basin, nor does each producer. The market generally sorts out these disconnects. In a broad sense, the greater the mismatch between production, demand and the nuances of pipeline outflows, the wider the differential the supply hub would be compared to any downstream demand hub. In the case of the Permian, natural gas prices around the Waha, Texas trading hub have become increasingly discounted against Henry Hub.
Waha Prices Retreat
The price discount at the Waha Hub compared to the national benchmark at Henry Hub has intensified in 2018, averaging ($0.72)/MMBtu. This is nearly a $0.50/MMBtu decrease from year-to-date last year, according to OPIS natural gas price tracking data. Since mid-April 2018, cash basis at Waha has been wider than ($1.00)/MMBtu regularly.
Shippers who hold pipeline capacity out of the Permian are seeing wider spreads in 2018 compared to last year. The graph below looks at the spread from Waha going west at the southern California border (SoCal), going north (NGPL’s Midcon Pool) and east to the Houston Ship Channel (HSC). Compared to last year, the spread from Waha, according to OPIS natural gas prices, has increased by $0.12, $0.22 and $0.57/MMBtu, respectively. Surely, these select exit routes are attractive, and as we’ll see, increased outflows have followed suit.
Permian Summary View
Pipeline exit routes for natural gas leaving the Permian consist of a mix of interstate pipelines moving north, west and south to the Mexico border. The route heading east falls to a half-dozen intrastate pipelines heading to the Dallas and Houston/Gulf Coast markets. Total outflow capacity away from the Permian is estimated to be roughly 12 Bcf/d.
If cash basis at Waha is running roughly ($1.00)/MMBtu and production is roughly 7 Bcf/d, but exit capacity is pegged at 12 Bcf/d, what gives? What's the problem? Short answer is, there is an abundance of underutilized capacity headed south to Mexico, while outflows moving west, north and east are pushing closer to effective capacity limits for the other exit corridors.
Below is a graphical representation of Permain production stacked up against localized demand and the four high-level corridors for gas to exit the region, according to OPIS PointLogic modeled data. While some of the production surge in 2017 and 2018 was consumed locally or piped across the border, it’s been a combination of incremental outflows moving north and east that have absorbed the majority of the growth.
The Permian has 110 Bcf of storage working capacity and about 1.5 Bcf/d of withdrawal capability, according to EIA data. While some of the storage fields are exclusively connected to distribution companies and intrastate pipelines, the vast majority of the activity is visible from an interstate pipeline perspective. However, utilization of storage is low and not really a driver in helping mitigate the abundance of gas supplies within the region.
Let’s begin with Permian pipeline exports to Mexico. While exports to our southern neighbor are rising, they still constitute a marginal volume. But, this route has the potential to really rise significantly in the years to come. Throughout 2016-2017 several intrastate pipeline projects to move Permian gas to the border went into service, lifting border capacity to over 3 Bcf/d.
While actual export volumes increased, the growth was nowhere near the capacity growth of the new projects. The limiting issue for U.S. exports to Mexico exists on the Mexican side of the border, which we covered in a Get the Point in March, As U.S. – Mexico Gas Flows Rise, So Does Clarity on Future.
The low utilization of export capacity boils down to some infrastructure delays on pipelines that connect into U.S. gas coming across the Mexican border as well as the gradual rise of gas-fired power generation demand. A few new Mexican pipelines that help pull Permian gas further south within Mexico were expected to come in service this summer. However, it is now expected the affected projects won’t come online until year-end 2018 or early 2019. These delays don’t bode well for Permian producers hoping Mexican demand would surge this summer and provide relief to low gas prices.
Gas exiting the Permian to the west not only helps to meet the demand needs of New Mexico and Arizona, it also is used as export gas along the Arizona border and for the needs of Southern California. The California gas demand market can be volatile, depending on hydropower conditions in the region. Also, it's susceptible to changes in the power generation stack—namely, increasing reliance on renewables. For more on this, read our April 25 Get the Point, How California’s Gas Future is Shaping Up.
The primary options going west are on El Paso Natural Gas (EPNG) and Transwestern Pipeline (TW). The red dashed line in the graph above, shows the exit capacity of all of the branches of the aforementioned pipelines if they were to flow west. The black dashed line is effective capacity, or a reflection of current market conditions. EPNG’s San Juan Crossover segment is bi-directional and frequently flips back and forth by marginal amounts, based on San Juan Basin production and demand needs further west. We reduced the exit capacity by that amount.
Cumulative westbound outflows have reached as high as 3.0 Bcf/d in some months and are currently estimated at 2.6 Bcf/d. Thus, approximately 0.4 Bcf/d of capacity is available—or is it?
Both EPNG and TW gather supply in basins besides the Permian, so while one pipeline may individually be highly restricted leaving the Permian, the other may face bottlenecks further downstream once other supplies are added. On top of that are system constraints within the Permian. Ultimately, pipeline utilization heading west is constrained by the amount of demand, or more precisely— the lack of demand—in the Southern California market.
Pipeline gas traveling north via the likes of EPNG, Natural Gas Pipeline of America (NGPL) and Northern Natural and an intrastate system can reach up to 1.2 Bcf/d. Until recently, this exit corridor had some sizeable capacity that remained underutilized. In the last few months, however, only about 0.2 – 0.3 Bcf/d of space remained open. The year-on-year rise in northbound outflows accounts for about one-third of rising Permian production. These molecules are displacing Midcontinent and Rockies volumes that aid in delivering gas supplies into the Midwest.
Completing our circle around the Permian is how much gas can exit towards the east, which happens to be all on Texas intrastate pipelines. OPIS PointLogic estimates that eastbound flows from the Permian are within 0.5 Bcf/d of reaching capacity. Connectivity to the network of intrastate pipelines varies greatly among receipt locations within the Permian and among the producers themselves. It is not a completely efficient playing field.
On May 4, Enterprise Products Partners and Energy Transfer Partners announced they were forming a joint-venture to reinstate Old Ocean natural gas pipeline, essentially idled since 2012 due to years-long litigation between the two companies. At one time, Old Ocean was planned to be converted to a crude oil pipeline to help bring Cushing volume to Houston. (Anyone remember the Double E Pipeline Project? This is unrelated to Summit Midstream’s natural gas pipeline project under the same name.) Old Ocean essentially moves intrastate gas from Dallas/Ft. Worth area to the Houston area and is expected to re-enter service by the end of June. By the end of 2018, the jointly owned North Texas Pipeline, which originates from the Permian, will also be expanded to help facilitate gas flows from the Permian to Dallas/Ft. Worth and then down to Houston.
A few of the key operators in the Permian mentioned growing gas production by 22%-45% year-on-year during the final quarter. What would happen if total dry gas production grew by similar percentages and how would that stack up against outflow potential?
The following is purely a hypothetical and for illustration only: it is not a forecast. Let’s assume three different production scenarios in which year-end production grows 15%, 20% or 45% annually. Then for simplicity’s sake, let’s assume outflow capacity going west, north and east are maxed out. With all this cheap shale gas, let’s assume power demand growth helps increase Permian demand each month by 5% compared to that same month of the following year and that monthly exports to Mexico increase by 10%.
There are at least four large-scale publicly announced intrastate projects to help take Permian gas east towards the Gulf Coast, a large portion of which is timed with LNG export projects. It is beyond the scope of this article to go into great detail each of the projects, but suffice it to say these four projects add up to nearly 8 Bcf/d of incremental takeaway, if they were all to come to fruition. Three of the projects have announced start dates by the end of 2020. These three projects are incorporated within the graph below.
It is unlikely that the outlet corridors heading west, north and east would be 100% utilized. Thus, based on the more conservative annual production growth rate of 15%, a more intensive market reckoning would be in order prior to the second half of summer 2019. Until then, there is limited space on the corridors exiting the Permian, albeit for not much longer.
As we mentioned in Part I of “The Mighty Permian,” producers are already flaring gas and asking for extensions to flare beyond the standard statutory limit. It is not expected that increased flaring will be a complete solution, but it can buy time that oil-driven producers need to get infrastructure projects in place. Thus, it is likely that Permian gas prices will continue to get worse before they get better. The forward basis curve indicates Waha could weaken by another $0.50/MMBtu, placing it ($1.50)/MMBtu from Henry Hub later this year and for months during 2019. It’s not until the start of winter 2019/20 when at least one of the new gas pipeline projects is expected to come into service that strength will come back to the Waha basis pricing, helping its discount fall back below ($1.00)/MMBtu.
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