Part 2: Six Ways Injection Disposal Restrictions Could Adversely Impact Delaware Basin E&Ps and Water Midstream Operators

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**Please note that the opinions expressed in this piece are the author’s only and do not reflect any official positions of Rice University or the Baker Institute for Public Policy.**

I’ve already given the basic background of the rules—to the extent it is available—in Part 1 of this series. This piece dives a level deeper and examines potential impacts of injection disposal restrictions in Reeves County and potentially, more broadly across the Texas Delaware Basin oil and gas space. My current analysis is a “hot read” and will almost certainly evolve as the RRC releases more information and, ideally, publishes the rules for public scrutiny. 

Six issues jump out at me as being especially important. As I lay these out, I’m also explicitly assuming that the audience is collectively far smarter than me and will likely call my attention to additional areas that this first-cut analysis might omit. If that happens, I’ll amend the analysis. One final point: the situation today likely does not warrant the imposition of draconian injection volume restrictions as we’ve seen happen in parts of Oklahoma and so many of the scenarios assessed here are currently best thought of as “bad case” potentialities.

 Issue 1: Water Midstream Business Models—and Potential Enterprise Valuations—Could Take a Big Hit in Some Areas

SWDs account for a significant portion of CAPEX in water midstream systems—in some cases, disposal wells can account for more than twice the capital expense share of the pipelines that move the water.[i] As such, if the number of SWDs needed to handle a given volume of water increases because injection restrictions allow fewer barrels per well, the economic impairment to a system can be dramatic since a large capital recovery must be divided among the same—or perhaps fewer—barrels than the system developer originally anticipated handling.

Consider the following simplistic illustration, which omits the cost of money over time and desired rates of financial return. If I need to recover $100 dollars in capital and will run 100 barrels through my system, I can charge $1 barrel to recover that capital. But if I now have to spend $150 in capital because regulations force me to build additional infrastructure, but I still can only run 100 barrels through the system, the capital recovery fee is now $1.50 per barrel. At best, this dents the economic returns and at worst, could render some systems economically unviable.

Investors would likely react poorly to development like those described above, making it tougher to raise money for new systems/system expansions, and depressing the potential sale values of assets poised for liquidity events. Consider, for instance, the example of Waterbridge, which filed a confidential Form S-1 in June 2018 in anticipation of a potential IPO.[1] WaterBridge recently spent $325 million to buy Halcón’s water assets in Pecos County near the Reeves/Pecos border area, and the firm’s total acquisitions and organic CAPEX expenditures in Reeves and Pecos counties in and near the areas where seismic activity has garnered regulators’ attention is likely significantly higher.[ii]

It is not inconceivable that WaterBridge could have $500 million or more of assets at stake in the areas proximate to seismic activity and thus potentially subject to future injection restrictions, if regulators decided this was warranted. Even if restrictions are not imposed right out of the gate, potential stock or asset buyers might demand discounts to price that risk in, which would likely then weigh on the assets’ market value—perhaps in a significant way. Only time will tell, but the potential for regulatory restrictions on volume throughput in assets that rely critically on being maximally utilized is one worthy of serious consideration and is a risk factor that did not hold much credence even a year ago, but is now increasingly real. And WaterBridge is not the only party in this position. Some of Rattler Midstream’s assets sit in areas uncomfortably close to recent detected seismicity.

Exhibit 1: The Potential “At-Risk” Area Encompasses Much of Southern and Eastern Reeves County (red dots denote detected seismic events from January thru November 2018)

Reeves County Earthquake Risk Zone_2018 thru November

Source: TexNet, Texas DoT

 

Issue 2:  Produced Water Recycling Volumes Will Likely Increase Significantly In and Near Areas That Have Recently Displayed Seismic Activity

If disposal systems are de-rated in an area in response to seismic activity, produced water will need to find a new home and provided that completions activity is sufficient in the area, much of that water will likely find its replacement home in a frac pond.

A key unanswered question here is whether operators will pre-emptively move to boost recycling levels in response to coming rules, or whether they will take more of a “wait and see” approach and respond tactically if and when injection cutbacks are imposed in an area. Historical experience suggests that proactive responses can be a tough internal sell and that it is easier to shift practices once a firm feels the pain of water that needs to go somewhere and fast, or else risk having to shut in wells.

However, an entirely different factor may coincide with the new regulatory anvil currently being mulled by the RRC and stimulate the greater adoption of recycling in the Delaware Basin, particularly in areas poised to scale up drilling if commodity prices permit. That factor is capital investment optimization. Produced water flows are extremely “peaky,” with a sizeable portion of total water from a wellbore front-loaded in the first few months of frac flowback and initial production.

Building fixed infrastructure—i.e. pipelines and SWDs—to fully accommodate peak flows thus risks leaving behind stranded capital as flows taper over time and the system remains underutilized.  One possible alternative would be to rely more heavily on recycling upfront to handle peak flows, and then build fixed infrastructure more closely aligned with anticipated longer-term volume trends. Here are the rough numbers behind such a “peak shaving” approach:  to handle 50 kbd of flows would likely cost $10-to-$13 million using SWDs injecting into the Delaware Sands and $16-to-$24 million using deep Devonian disposal wells, but only $2.25 million using mobile ozone-based water treatment units supported by 1 million bbl of pond capacity (Exhibit 2).

Exhibit 2:  Using Recycling to Optimize Oilfield Water CAPEX

Using water recycling to optimize oilfield water CAPEX

Issue 3: More E&Ps and Water Midstream Firms May Begin to Consider More Dramatic Scale-Up Options For Evacuating Water From Reeves County

The rising volume of produced water challenges operators because (1) high-intensity shallow injection risks operational interference with existing production wells and future drilling and (2) shifting volumes currently disposed of in the Delaware sands and anticipated volumes from future Hz activity increases to deeper Devonian/Silurian injectors would require substantial increases in water management CAPEX and OPEX, while also potentially exacerbating seismic risks. What’s more, recycling alone will not solve the water problem for many large operators because even with aggressive frac completion schedules, they would still have a net surplus of water even if they recycled all of their own produced water output.

It is thus far unclear what the impacts of energizing deeper rock layers in the Delaware Basin through increased water disposal activity might be. For instance, recent geophysical research on induced seismicity in Oklahoma suggests that injection disposal of water may have reactivated faults in basement rocks that were essentially dormant for millions of years. To reiterate, Texas is not Oklahoma, but the law of unintended consequences merits attention as regulators consider various scenarios.

As events unfold, one potential response is to evacuate water from Reeves County and dispose of it elsewhere. For instance, Goodnight Midstream has signed a multi-year agreement with Callon Petroleum under which it will take produced water from Callon’s Spur assets in Ward County and pipe it to disposal wells on the Central Basin Platform, which is geologically distinct from the Delaware Basin.

Issue 4: E&Ps and Water Midstream Firms May Also Begin to More Seriously Consider “Moonshot” Infrastructure Projects That Aim to Evacuate Water From the Permian Basin Entirely

As water volumes in the Basin continue to rise, producers may begin to think about projects that export produced water far from the Basin—perhaps even to the Gulf of Mexico for disposal into the sea or into depleted offshore fields. I do not presently have a handle on what the economics look like for moving water from Corpus Christi out to depleted offshore fields and injecting it, but my initial back of the envelope calculations suggest that the combined CAPEX-OPEX cost of moving a barrel of produced water from Orla to Corpus Christi is likely under $1.00/bbl, depending on the level of pre-treatment cost required (Exhibit 3).

Two existing pipeline projects offer loose analogies that can be used to anchor initial estimates. For the route length, the EPIC crude oil pipeline project offers a sense of the “real world” distance a Delaware Basin-Gulf of Mexico pipeline would need to cover. Retracing EPIC’s route starting in Orla and ending near Corpus suggests the system would be about 650 miles long, including a spur up into the Midland area.

For the cost and capacity of a potential large-bore water pipeline, I use the Vista Ridge project now under construction between Burleson County and the city of San Antonio.  Vista Ridge is a 142-mile, 54-inch steel line that is slated to enter service in 2020 and will transport 50,000 acre-feet per year of water at full operational capacity. That equates to about 1 million bpd of water. The line will cost an estimated $930 million to build, including supporting infrastructure such as gathering lines for the wellfield feeding the project and storage tanks, implying an all-in cost of $6.5 million/mile.

If we assume that: (1) Five such lines would be built in parallel to evacuate 5 million bpd of produced water from the Permian Basin (not a likely scenario, but useful as a though exercise); (2) The large-scale construction would yield economies of scale worth 25% of project value and; (3) That water would be moved all the way to the Gulf, the total project cost would be about $16 billion. Financing that amount with a 20-year loan at an interest rate of 4.5% would imply a CAPEX cost of $0.66/bbl moved.  If the project were operated at something closer to a commercially desirable rate of return of 10%, that CAPEX cost would rise to about $1/bbl transported (assuming 5 million bpd average volume).

The power and O&M costs for the Vista Ridge project suggest an OPEX total of approximately $0.00035/bbl/mile. Power costs would likely be lower given that much of the route between the Permian Basin and GoM could capitalize on gravity given the large elevation drop. But produced water would likely need to be pre-treated before entering the line and its saline and corrosive nature would likely necessitate much more maintenance than a freshwater pipeline like Vista Ridge would require. So the margin of error on my rough initial estimates is wide, but they suggest the “raw” economics of a long-haul transport project could potentially be competitive with more intensive in-Basin treatments such as desalination that would be required for re-purposing produced water for use outside the oilfield.

 Exhibit 3: Economics of Hypothetical Orla-Corpus Christi Produced Water Pipeline

Permian produced Water Unorthodox Solutions

 Source: Garney, SAWS, Author’s Estimates 

Issue 4: Texas May No Longer Be a Desirable “SWD Backyard” For Producers Facing Disposal Challenges in Southeast New Mexico

As it has become more difficult to obtain disposal permits in New Mexico, a number of parties have sought to increase their capacity to transport produced water south and dispose of it in Texas, where to date the Texas RRC has been more permissive than the New Mexico OCD.

A simple ratio analysis of total water produced divided by total water injected in Eddy and Lea Counties implies a meaningful and fairly steady decline of local injection since 2012, around the time the horizontal drilling boom began to pick up steam.

Exhibit 4: Is Texas Becoming the New Mexico Oilfield’s Water Disposal Hinterland?

Texas as New Mexico disposal hinterland

While not conclusive, the downward trend suggests greater exports of NM-origin water to Texas disposals.  Anecdotal data from water midstream operators such as Solaris and NGL further suggests that sector participants perceive a significant cross-border arbitrage opportunity whereby they can export freshwater northbound from Texas to New Mexico at a premium price and then backhaul produced water southbound for disposal in Texas.

As these developments unfold, it is not rocket science to see that disposal restrictions in Texas could place New Mexico production assets and their water service providers in a double-sided bind. Thus far, the focal points of known seismicity in Reeves County are from the city of Pecos southward, but if monitoring begins to detect seismic activity further north in Reeves (or Loving) counties, those areas could face a regulatory risk that the water midstream market has not yet priced in.

 Issue 5: Equity Markets May Begin to Assign Value Premiums to Delaware Basin-Centric Producers With Lower Water Cuts per BOE and Those With Premium Rock Outside of Areas With Significant Seismic-Driven Regulatory Risks

This point is fairly self-explanatory, and I won’t dwell on it for now.

 Issue 6: Injection Restrictions Would Strengthen the Case for Increased Integration Between Existing and Planned Oilfield Water Infrastructure

Deeper integration between water midstream assets would need to surmount a range of legal and water chemistry concerns. Macro shifts, be they commodity price movements or regulatory developments, can break this stasis and catalyze innovation and adaptation. The prolonged price depression between late 2014 and mid-2018 prompted E&Ps to focus on efficiency in a way that they frankly just did not have time or incentive to during the go-go period preceding the 2014 price crash.

Furthermore, another dynamic was layered atop the discipline imposed by the downturn: operators were choosing en masse to emphasize Permian development over plays elsewhere in the US and globally. The confluence of these trends meant that CAPEX discipline, intensifying operations, and moves toward development at scale merged in the Midland and Delaware Basins, with impressive results.  Consider for instance the trend in Devon Energy’s Delaware Basin lease operating expenses, which the company reports declined from nearly $17/barrel of oil equivalent (BOE) produced in 1Q2015 to $5.48/BOE by 2Q2018 (Exhibit 5).

Exhibit 5: Integration of Infrastructure and Its Effects on Permian Costs at the Operator Level

Devon Slashes Delaware Basin Operating Costs

Devon’s trend is mirrored by other E&Ps that leveraged scale and operational excellence to drive down costs. The question that arises now is what the potential gains from greater integration of infrastructure between operators might be. Water midstream providers are doing this to some extent in some areas, but there may also be a case for E&Ps themselves to consider deeper integration between assets that are critical to operations but where companies can cooperate without losing their relative competitive edge.

As the industry ponders potential shared infrastructure opportunities, there is almost certainly an opening to drive costs further down, but perhaps the biggest economic gain could come from acquiring broader—and longer-lasting—control over costs. Service cost inflation has been a major thorn in E&Ps side and the case for common infrastructure that bolsters all participants’ competitive position relative to producers elsewhere in the world becomes stronger in a disposal-constrained environment.

The potential injection restrictions currently under consideration at the RRC may end up being a tempest in a teacup, as they could be watered down significantly (pun intended) or be structured in such a way that they exist on the books but are rarely enforced in practice. This author’s view is that the current seismicity situation in the Texas Delaware Basin probably does not justify nearly as interventionist a regulatory approach as that taken in Oklahoma. It is also likely that RRC disposal restrictions that materially affected industry operations in Reeves County would engender a robust backlash from a range of stakeholders, which would probably lead to rules being dialed back. But assuming continuation of the status quo is never a wise course of action and it is in that spirit that I have written this “hot read” analysis.

[1] “WaterBridge Resources LLC Announces Confidential Submission Of Draft Registration Statement By WaterBridge Partners LP,”  https://www.streetinsider.com/Press+Releases/WaterBridge+Resources+LLC+Announces+Confidential+Submission+Of+Draft+Registration+Statement+By+WaterBridge+Partners+LP/14328223.html

[i] See, for instance Jim Summers, “A New Midstream Model for Water,” Permian Basin Water in Energy Conference 2018, Midland, TX, 22 February 2018. https://www.pbwiec.com/presentations/

[ii] Halcon Resources 3Q2018 SEC Form 10-Q, available at https://seekingalpha.com/filing/4229868

Please cite as:

Gabriel Collins, “Part 2: What Injection Disposal Restrictions Could Mean for Delaware Basin E&Ps and Water Midstream Operators,” Texas Water Intelligence™, Water Note #9, 10 December 2018

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