What is This? What’s in the Air? We Need a Comprehensive Approach to Managing Pollution

 by Stephanie Coates, UH Energy, University of Houston

When a waterway is deemed too heavily polluted, there is a federal protocol that state and local authorities can follow to measure pollutants, evaluate and enforce cleanup of the waterway. When air becomes too heavily polluted in an environmental “hotspot,” there is no similar mechanism.

And people living in these hotspots too often pay the price.

It’s essential to regulate air pollution, not only for the sake of clean air but also for the health of communities living nearest the highest concentrations. We already have a model for how to do that in the Clean Water Act.

Under the Clean Water Act, if a state identifies a waterway that is “impaired,” or in danger of not meeting water quality standards, the state is supposed to calculate the pollution affecting the waterway and determine a plan, or Total Maximum Daily Load (TMDL), to reduce the pollution to levels that meet water quality standards. Part of the plan includes identifying the sources of pollution and, determining how to allocate responsibility among the various sources for reducing the pollutants to an overall acceptable level.

The plan is implemented and the waterway is then reassessed.

As the graphic demonstrates, states are constantly reevaluating and updating their plans throughout this process and moving their waterways toward meeting cleaner standards.

WLA is the sum of wasteload allocations (point sources), LA is the sum of load allocations (nonpoint sources and background) and MOS is the margin of safety.EPA

Source: https://www.epa.gov/tmdl/program-overview-impaired-waters-and-tmdls

A key feature of this process is that if a body of water is threatened by more than one pollutant, TMDLs account for the heavier cumulative load posed by multiple pollutants, then permits for sources of pollution are issued through the Environmental Protection Agency’s National Pollutant Discharge Elimination System, or NPDES program.

There isn’t a comparable plan for air pollution.

The EPA sets limits for six pollutants, including carbon monoxide and lead, but what if an area is already exposed to several pollutants and a company there is seeking a permit for another? Or if an area experiences emissions of a chemical not on the EPA list?

Since there is nothing like a Total Maximum Daily Load for air pollutants – which would set overall levels allowed, adjusting for how many types of pollution are found in one geographic area – communities in “hotspots” are pitted against individual emitters and have to fight each new pollutant one at a time,  without federal support. The situation is exacerbated by the lack of a flexible process for evaluating and lowering those pollutants.

Public health is potentially at risk.

As an example of how this is playing out, consider the permit fight between Valero Refining – Texas, LP, and the community of Manchester, the southeast Houston neighborhood where the refinery is located.

The Texas Commission on Environmental Quality (TCEQ) in June held a public meeting to take comments on a permit Valero requested to authorize already existing emissions of hydrogen cyanide from the Fluid Catalytic Cracking (FCC) Unit. Emissions of hydrogen cyanide (HCN) have been occurring since the cracking unit was deployed, but Valero was not previously required to track them. However, the EPA recently started requiring testing for HCN, meaning the company needed an addendum to its existing permit for other types of emissions at the site.

According to the notice published by TCEQ, after reviewing the technical aspects of the amendment, the agency’s executive director “made a preliminary decision to issue the permit because it meets all rules and regulations.” The executive director of TCEQ appeared to see it as a straightforward issue and granted preliminary approval.

But to the citizens testifying at the public meeting, the permit feels like another nail in the coffin.

The town of Manchester, zip code 77012, straddles Interstate-10 and sits in a fork of Buffalo Bayou at the Houston Ship Channel – the interstate and ship channel are both heavily trafficked. Other prominent features of the immediate neighborhood include a fertilizer plant, two recycling facilities, two refineries including Valero, and the Union Pacific train yard. A number of chemical plants sit within a three-mile radius.

The University of Texas School of Public Health found a possible link between cancer risk in the area and the air pollutants. In 2016, the Union of Concerned Scientists concluded similarly and also noted that the risk of respiratory hazards is 24 percent greater in Manchester than in more affluent parts of Houston.

At the public meeting with representatives from TCEQ, residents reported health-related issues, including frequent nosebleeds, asthma and headaches. Without regulations on total air quality, it was easy for TCEQ to dismiss the complaints. It is not the hydrogen cyanide alone that causes all the noted health problems, but that was the only issue being considered.

HCN is a neurotoxin, and at high concentrations causes death. Lower chronic exposure can cause headaches, weakness, nausea and enlarged thyroid, but HCN is also lighter than air. That means when it’s released from the refinery, it usually rises rapidly and since it is being emitted from a tall stack, it will be able to disperse into the atmosphere to break down (albeit slowly). At that point, most people would not consider it a health risk.

In July 2017, TCEQ wrote an interoffice memo regarding the health effects from the emissions related to the new permit. It concludes that they “do not anticipate any short- or long-term adverse health effects to occur among the general public as a result of exposure to the proposed emissions from this facility.”

However, this memo intended to attest to the health risk does not examine the already existing total accumulation of emissions, nor how allowing the HCN emissions impacts the risk. It does not consider the possibility of potential leaks or other unplanned emissions, or potential explosions.

Without an overarching federal rule requiring it to do so, TCEQ, although it could do otherwise, grants permit requests for each individual chemical emitted at each individual facility instead of considering the overall impact of adding hydrogen cyanide to the pollution mix over Manchester.

In this permit fight, Valero is not to be seen as an enemy or villain – many Manchester residents work at the refinery, which by at least some accounts has been a good and responsive neighbor.

In fact, we can’t blame any individual refinery, especially since emissions only come as a by-product of supplying the gas, chemicals and other valuable consumer products we all demand.

The cumulative risk – not only the air quality risk posed by total pollutants, but also the health risk from pollutants in an area already made vulnerable by the fact that so many residents are poor, members of a minority ethnic or racial group and speak limited English – should be considered when permitting an additional facility or more emissions. We have a system for reporting air pollution emissions through the Toxic Release Inventory, for example, but after we collect and report the data, we don’t do enough to ensure the safety of affected communities. As it is now, health risk is only assessed as individual chemicals newly become regulated, as in the case of HCN; even then, the assessment is incomplete since it does not address total ambient air quality.

Limiting the overall load of air pollutants is a better way to address hotspots and is already working well under the Clean Water Act.

Residents haven’t given up the fight against allowing hydrogen cyanide emissions at the Valero refinery, but the odds aren’t in their favor. Until Manchester and similar communities have a better way to deal with the source of public health problems, they will need to keep fighting, one chemical at a time.

Stephanie Coates is a member of the staff at UH Energy and is a graduate student, pursuing her master’s degree in public policy, along with her master’s degree in social work at the University of Houston. She has received several awards including the Phi Alpha Honor Society Scholarship, Women’s and Gender Resource Center Scholarship and the Hobby School of Excellence Scholarship. Stephanie is a member of MACRO Student Organization and serves on the Student Center Policy Board, where she chairs the subcommittee for Facilities Use and Planning.  She serves on the UH Sustainability Committee and volunteers with Staff Council. Stephanie has a bachelor’s degree in Spanish from the University of Houston.


What Happened To The IPO Market For Oil And Gas Independents?

There is no IPO market for oil and gas independents today. Why is this?  Because the market value of publicly traded shale companies today is less than the cost of replacing the leaseholds, seismic, reserves and drilling inventory that make up their assets. Consequently, cash-rich companies and private equity managers have acquired or merged publicly held companies into their portfolio companies to acquire assets more cheaply.

When will the market again favor private equity managers’ favored strategy of privately acquiring assets and then exiting to an overvalued public market? Simple: when market values exceed replacement costs.

To understand when that might happen, let’s take a quick look at the fundamentals driving today’s market.  After that we’ll look at some time-honored ways to view risk and reward.

The supply of public equities in oil and gas is disproportionately smaller than the use and the value of oil and gas in the national economy. “Market allocations” for oil and gas are underweighted now in the public equities market. Until there is a flow back into public equities, independents and their investors must rely upon excellent science to discover the next low-cost play, to drive down current drilling and operating expenses, and maintain positive cash flow. It will happen.

Consumers are short oil and gas for the rest of this year, next year and the years afterward, no matter how much they plan to use. Threats of supply shortfalls lead to remarkable inflows of capital, price increases in the futures markets, surging equity prices, and overweighting of oil and gas equities in the portfolios of institutional investors. Always.

The current price elasticity of demand for oil is negative0.04. This means that a relatively small change in world supply changes the price (in the opposite direction) by 25%.

This lack of elasticity is what Saudi Arabia used to take aim at U.S. shale drillers in 2014, resulting in a catastrophic loss of capital, 330-plus bankruptcies, 250,000 direct jobs lost and more than $200 billion in lost annual GDP. This lack of elasticity also means that despite current sentiment that the world has plenty of oil and gas and that peak demand is only a few years away, OPEC has succeeded in withdrawing sufficient oil supplies to drive up the price from $40 per barrel to more than $60.

Note that “Peak Oil” supply has always been a quaint fiction — especially so in the price regulated U.S. market in which the notion was advanced. Increased demand and higher prices will draw out more supply, putting upward pressure on prices. The 2009 Energy Journal paper “Depletion and the Future Availability of Petroleum Resources” lays out the supply availability of oil, gas and gas liquids as the real price increases and allows for economic production.

The biennial study of the Potential Gas Committee details that gas resources will last well beyond several lifetimes. The marginal cost of producing natural gas from the Barnett and Haynesville shales was about $1 per Mcf in 2011. That number has only decreased as technology has improved by leaps and bounds.

According to recent data, private equity sponsors have stakes in 350 portfolio companies to which $200 billion of equity has been added since 2014.

Much of this funding went to shore up expensive shale and offshore investments that were bleeding cash at $40 per barrel oil.

These ideas are not new. Time honored analysis

  • In a 1931 article, Stanford University professor Harold Hotelling detailed conditions under which the owner of a limited amount of natural resources would be indifferent between current production and future production if the forecast price increase of the resource was equal to the rate of interest. Known U.S. shale plays offer the certainty of hydrocarbons — essentially, storage in place — the commercial production of which is entirely dependent upon the current gross margin.

Barring supply manipulations elsewhere in the world, investors today in the U.S. domestic shale plays face the prospect of bringing oil to market when the long run prospects for price exceeding marginal costs are not good and, in fact, while the prospect of price increasing at a rate greater than the rate of interest is decidedly negative.

  • Yale University professor William Nordhaus forecastin 1979 that the real price of crude oil would increase at the rate of real economic growth. Discounting short run manipulations by OPEC, misguided political responses and reactions by producers and consumers adjusting to these divergences, the real price of crude has indeed increased at the rate of real economic growth for the past 40 years. The manipulations and reactions have provided the volatility needed for smart active investors to realize outsized returns.
  • One’s level of success depends on what others do. Think John Nash of “A Beautiful Mind” and his paper “Non-Cooperative Games.” OPEC remains the “swing” producer in the global oil market. The U.S. shale plays have improved their costs, but one cannot characterize these high cost producers as “swing” producers because they do not have the incentives or abilities to increase or decrease production at will.

In recent decades, OPEC works backward to assign quotas based on their assessment of world demand and non-OPEC production. OPEC’s quotas were designed to provide an intersection of supply and demand at a forecast price. OPEC often got it right, but when it failed to respond rapidly to China’s 2008 increased demand (necessary to replace coal to clean up the air before the Beijing Olympics), OPEC inadvertently created a new competitor; the U.S. shale plays. By 2013, it was obvious that the U.S. shale plays had encroached on OPEC market share and that OPEC would employ another Nash response, predatory pricing.

  • Martin Shubik is a titan of game theory and value investing, and in his Dollar Auction paper, he describes a game that investors must avoid. The auction is for a dollar bill. It is won by the high bidder, but the second-place bidder must also pay out his bid while gaining nothing. The Dollar Auction describes perfectly what happens when nations go to war; the winner survives (sometimes barely) and the loser is wiped out.

For some investors, the game also describes the challenge faced when too much money chases too few assets. Investors can find themselves upside down or bidding more than one dollar to win the asset, just to stay in the game.

  • The shale drillers that survived $40 oil are those who followed the dictum of Michael Porter’s book “Competitive Strategy” – be the lowest cost producers. For commodities, it is the only strategy that succeeds over the long run.

Private Equity Game

Private equity sponsors have become larger and larger over the past 20 years.   Portfolio companies backed by hundreds of millions of dollars are rarely allowed to make money on new discoveries and new drilling. Nowadays, they are kept on short leashes and directed to infill drilling of known shale plays that commonly have inbound costs of $30,000 to $40,000 per acre. Ouch! These numbers are reflected in the publicly traded companies adjacent to the private companies in the shale plays.

Here, we see that the efficient market hypothesis and Stephen Ross’ Arbitrage Price Model begin to work against outsize returns for the shale play companies and especially against those that have to pay a premium price for entry. In this instance, the sponsor may be better served by making a long-only bet on NYMEX and avoiding the liabilities of owning an operating company.

The time horizons of sponsors do not match those of their pension fund and endowment investors. Institutional investors typically invest in oil and gas as a hedge against increasing energy prices and for diversification. Private equity sponsors have shorter horizons (generally not more than seven years for a fund) and, consequently, their portfolio companies have shorter time horizons. With cycles and manipulations by OPEC occurring over years and even decades, there is often a mismatch of timing among capital providers and their investments.

Where is the opportunity now?

Let’s define microindependents as small oil and gas ventures that have the potential to be company makers. The companies have a competitive advantage in proprietary science and perhaps a portfolio land position. They may or may not have production, but no one can dispute the risk-reward profile they offer to investors. These are not the one-well projects with the prospect of a trillion cubic feet (TCF) payoff but the portfolio of a half-dozen targets with a TCF payoff. It is difficult for a microindependent to be so well diversified but easy for a private equity portfolio company to assemble a portfolio of such geologically independent targets. $50 million to $100 million of investment is needed to get one of these companies over the threshold. No one forgets the lesson of Newfield Exploration’s first 11 busted wells and the success that came with the 12th, which paid for first 11 and more. This approach does not exclude shale plays per se, but it excludes the strategy of paying top dollar to buy into the current roster of producing shale plays.

Investment strategies that provide investor exposure to upside beyond simple oil price increases will dominate. The options pricing models, however limited, argue in favor of equity investment in assets with higher risks coupled with high potential. See, for example, the Cox, Ross, Rubenstein model or Stanford professor Myron Scholes’ recent workthat directs investment managers to move away from “average” or “The Black Swan” by Nassim Nicholas Taleb of New York University.

Profitably selling oil and gas is the first exit.  Fundamentals and risk analysis never go out of style.

Ed Hirs is a BDO Fellow for Natural Resources and a UH Energy Fellow at the University of Houston.   He teaches energy economics courses to undergraduate and graduate students within the department of economics at the University of Houston. He is also Managing Director for Hillhouse Resources, LLC, an independent E&P company developing onshore conventional oil and gas discoveries on the Texas Gulf Coast.  Previously, Ed was CFO of DJ Resources, Inc., an early leader in the Niobrara Shale. He holds a Bachelor of Arts with honors and distinction in Economics, a Masters in Economics, and a MBA from Yale and holds the CFA designation. 

UH Energy is the University of Houston’s hub for energy education, research and technology incubation, working to shape the energy future and forge new business approaches in the energy industry.

LNG Projects Have Stalled. A New Business Model Could Help

by Chris Ross, Executive Professor, Finance, University of Houston and Justin Varghese, MBA Candidate, Bauer College of Business

Liquefied natural gas (LNG) developers and natural gas producers have depended on third parties to create demand for their product. In recent years, LNG market prices have dropped in response to a surge in supplies and roughly two million tons of LNG contracts are set to expire in the next 10 years. Promising new LNG projects cannot be financed and have stalled.

Developers need to do more to encourage end users – including industrial users and electric generation facilities – to switch from diesel and other liquid fuels to LNG. A new business model could help. We propose a broad collaborative, including natural gas producers, pipeline companies, Engineering, Procurement and Construction (EPC) companies, equipment manufacturers and end users to accelerate market growth.

The International Energy Agency predicts that global oil use will decline as it is replaced by natural gas and renewables. The collaboration we are proposing could accelerate the switch.

A Little Background

Early LNG developments in the 1970s were driven by oil companies that had the misfortune to discover natural gas distant from gas markets. The discovery would have been stranded but for the advent of integrated LNG developments to liquefy, transport and regasify the gas for use in power plants and local distribution. Although LNG was more expensive than oil, utilities in Japan and Europe were prepared to sign long term, take-or-pay contracts because of natural gas’ low emissions and enhanced energy security through the interdependence of buyer and seller and diversification from oil.

U.S. utilities signed similar deals with Sonatrach, the Algerian national oil company, but reneged when domestic production and pipeline companies were deregulated from 1978 through 1985 and advances in 3D seismic technologies opened the Gulf of Mexico shelf as a prolific hydrocarbons resource. A natural gas oversupply “bubble” caused prices to decline below the contractual costs of LNG, and a long arbitration process resulted in settlement agreements. Regasification plants were built, but essentially no LNG was delivered until the bubble deflated after 2000.

Meanwhile, successful lobbying encouraged new domestic natural gas demand, notably through cogeneration facilities that provided steam to industrial customers and sold surplus electricity into the grid at “avoided cost” that would have been incurred from a new power generator.

It is time to shake the dust off that playbook.

Recent LNG Contracting Evolution

Those early LNG sales contracts were all point-to-point, stressing the interdependence of buyer and seller. Cracks in the global contracting regime began to emerge in 1995 with Atlantic LNG’s waiver of destination restrictions. From its website: “Atlantic was often described as “The Trinidad Model”, which referred to the unique partnership between four energy majors and the Government of Trinidad and Tobago to form an LNG company. The model was unique too in its objective to target two dedicated primary markets at that time: the US East Coast and Spain, capitalizing on Trinidad and Tobago’s geographic proximity to these markets and therefore competitive delivery costs.” To further that goal, Atlantic successfully lowered the construction cost of its liquefaction plant below previous international LNG projects.

Fifteen years later, the majors led by ExxonMobil doubled the size of single liquefaction trains and the size of the LNG carriers as they invested in massive Qatargas LNG projects commissioned in 1998 through 2011. LNG supplies surged, and the global contracting regime could have come under extreme pressure (Figure 1).


However, on March 11, 2011, a massive earthquake offshore Japan caused a tsunami which killed thousands of people and inundated the Fukushima Diichi nuclear power plant. Failure of back-up systems resulted in a meltdown and release of radiation. In reaction, most nuclear power plants in Japan were shut down and fossil fuel power generation plants had to fill the supply gap; demand for LNG escalated and fortunately major new Qatar LNG plants were able to supply it.

A robust spot market soon emerged to provide incremental LNG supply to Japan beyond that assured under previously executed long term contracts. LNG prices rose to support new LNG plants in Australia to address growing Asian LNG demand.

At the same time global LNG suppliers were realizing premium prices for their spot sales, U.S. natural gas prices were under tremendous downward pressure in the face of the oversupply of unconventional gas.  The coupling of these premium LNG prices and the glut of U.S. gas combined to provide the economic incentive for the U.S. to evolve from LNG importer to exporter, adding to LNG capacity being built in Australia and Papua New Guinea (Figure 1).

Cheniere was first and pioneered a new tolling contracting model to support financing its Sabine Pass natural gas liquefaction complex. Under this model, buyers would acquire U.S. natural gas at spot market prices and make long term take-or-pay commitments to liquefy their gas in Cheniere’s facilities. Buyers took the risk that the delivered cost of LNG would be lower than it would be under a traditional oil-indexed contracting regime.

Table 1: Traditional and New LNG Contracting Models

International North America
Natural Gas Supply Integrated with field production Purchased at market prices
Liquefaction Cost Passed through by seller to buyer Long term tolling fee charged to buyer
Transportation Dedicated tanker fleet Buyer’s responsibility
Marketing/ Pricing Point-to-point long term S-Curve Cost Recovery
Price risk Passed to end user Buyer’s responsibility

Today we have two competing contracting models (Table 1): the traditional model still used for integrated LNG projects from reservoir through end user, with prices indexed to oil prices, coexisting with the new tolling model seen in the wave of U.S. liquefaction projects. This should provide arbitrage opportunities for global LNG traders, while LNG project developers will see enhanced spot liquidity as they optimize not only the rights they retained to process uncontracted volumes from the new projects but also those volumes from contracts which are soon to expire.

The problem with spot markets for a capital-intensive commodity such as LNG is that variable operating costs are low, especially for the traditional integrated field to liquefaction facilities. It costs very little to produce incremental volumes at the field, especially if condensate is a co-product. Any price above these costs will contribute positively to cash flow and the economic incentive will favor running the liquefaction complex at full utilization. The consequence was illustrated by the collapse of spot Japanese LNG prices in advance of crude oil in 2014 (Figure 2).


The market rebalanced in 2016 and 2017, but contracts were shorter term and covered lower volume, with prices influenced by local alternatives and less creditworthy buyers than in the past (Figure 3). New importing countries Egypt, Pakistan, Jordan, Jamaica and Colombia were added in 2016, showing newly price-elastic demand segments benefiting from pre-existing infrastructure but contributing to lower overall credit risk. Buyers have become more sophisticated and are putting together portfolios of contract supplies with different tenors and pricing but will soon need new downstream infrastructure to accommodate higher export volumes.

Figure 3: Deteriorating Contract Quality in 2016-17


Australian supplies continue to expand, the U.S. is emerging as a major LNG supplier and Qatar has promised to increase its LNG production 30% by 2020. Natural gas discoveries in the Levant Basin have the potential to supply Egypt, Jordan and Israel, displacing LNG imports in the next few years.

China and India both suffer from appalling air quality and benefit from switching from coal to natural gas in power generation. However, coal extraction is a major employer in both countries, and there are political risks in switching too fast. China and India will want to negotiate low prices based on coal economics; in the medium term the industry must find innovative ways to expand global LNG demand by providing end users with incentives to encourage a switch from oil to LNG.

Absent long-term contracts with high credit counterparties, it has become almost impossible for an independent LNG developer to finance the huge capital investment required for a new project, and major oil companies are demonstrating capital discipline. Domestic natural gas producers will struggle to find markets and prices will remain depressed as associated gas production increases. Project developers are trying different business models but fail to engage with end-users, hoping that low LNG prices alone will stimulate demand. Opening a new market segment has the potential to smooth the typical bust and boom commodity price cycle.

Unpacking the LNG Value Chain

It is helpful to start with an assessment of the LNG value chain and its participants (Figure 4) and then review some initiatives that address the need to finance new projects in a market where buyers are looking for flexible pricing mechanisms and are no longer receptive to long term take-or-pay contracts.


A wide range of countries and companies have a potential interest in successful development of new U.S. LNG projects that contribute to a broader and deeper LNG market, with prices below oil prices and reducing greenhouse gas emissions.

  • Natural gas producers would benefit from access to a new market segment of companies and utilities currently dependent on expensive diesel fuel and should be interested in a pricing mechanism linked to diesel prices.
  • EPC companies would benefit from the opportunity to provide services and equipment for the switching LNG customer as well as in the liquefaction complex and may be prepared to consider innovative contracting features.
  • Importers and traders may be prepared to take on some price risk to catalyze collaboration among disparate partners.
  • Investors and developers of independent LNG projects should be willing to consider innovative tolling fee structures to spread price risks among collaboration participants.
  • The federal government has expressed its support for LNG exports as helpful to narrowing the trade deficit and achieving “dominance” in global energy. Importing countries should welcome a transition from oil to natural gas as positive for air quality and competitiveness if priced below diesel.
  • End users may be willing to invest in switching to LNG as fuel at a price below diesel prices, so long as supplies are secure and reliable.

New Business Models

The traditional model is an integrated supply chain: IOCs and NOCs develop and operate the gas field, negotiate EPC contracts for construction of the liquefaction complex, sign charter parties with shipping companies, and often offer an ownership share to end use buyers. As the initial contracts reach their term, the IOCs have uncontracted volumes that they can recontract or sell in spot markets. Roughly two million tons of LNG contracts will expire in the next 10 years. The IOCs and publicly traded NOCs have strong balance sheets that can support new projects without recourse to project financing. Independent LNG project developers must find different business models.

The first movers for U.S. LNG exports were able to negotiate long term tolling contracts with creditworthy customers, allowing project financing of the liquefaction complexes. These have been difficult to secure in current times of low spot market LNG prices, where the large global commodity traders (e.g., Koch, Vitol, Trafigura) are finding opportunities to develop new LNG customers, using existing infrastructure and managing the credit risk as part of their risk portfolios. With access to long term take-or-pay contracts scarce, new business models are being tried by developers of new LNG projects with mixed results. However, most of these business models assume that increased LNG supplies will create their own market demand if the price is low enough. The problem is that the required price may not guarantee sufficient cash flow to service debt required to finance a new LNG project and higher prices would suppress new demand. Examples of new business models are:

  • Supply Chain Integration: Tellurian has devised an integrated LNG supply chain from natural gas resource through end use buyer. They have raised over $400 million from Total SA, Bechtel and public equity and have acquired 11,620 net acres in the Haynesville, taking advantage of low prices for natural gas reserves outside Appalachia. They have completed a FEED study for their subsidiary’s Driftwood LNG project and have signed a fixed price EPC contract with Bechtel. They have announced open seasons for planned pipelines connecting Permian and Haynesville production to its LNG project. They have reserved up to 40% of the equity for potential buyers so they can participate in the full U.S. natural gas supply chain. The complete project cost, excluding LNG tankers and regasification investment is estimated to be over $20 Billion: $7.3 billion for pipelines to supply the LNG plant, $15 Billion to build the liquefaction facility, plus further investments in acquiring natural gas resources.
  • LNG Demand Creation: AES LNG is a subsidiary of AES Corporation, an international electric power company. They “aim to radically improve the environmental and economic condition of many small liquid petroleum fuel consumers in the Caribbean, Central America and the northern parts of South America by substituting dirty and often expensive fuel oil or diesel with clean-burning natural gas.” Certainly, diesel prices in the Caribbean are set by U.S. Gulf Coast prices, which have historically been significantly above Henry Hub spot natural gas prices (Figure 5). The lowest annual Gulf Coast price spread was $4.96 in 2016, when oil prices were abnormally low. The price spread should most of the time be above $6/MMBtu, sufficient to cover debt finance of the liquefaction and regasification and fuel switching facilities and cover the higher LNG marine transport cost compared to diesel.


AES Dominicana has safely been operating the large-scale LNG receiving facility since its inception in 2003. The facility provides gas to AES Dominicana’s two gas-fired power plants as well as 50 industrial clients, two third-party power plants and 15,000 gas vehicles in the Dominican Republic. As well as serving the domestic market the terminal has capacity to serve the regional market. AES is currently constructing a second LNG receiving terminal in Panama to be completed in mid-2019, the first of its kind in Central America. With slightly larger capacity than AES Andres, the Colón terminal will serve AES Panama’s own 381MW power plant as well as the domestic and regional demand for gas. Both terminals are designed to receive LNG on standard large carriers of 125,000m3 – 175,000m3 and redistribute LNG via re-loading small bulk carriers and ISO containers.

Utilizing AES expertise and in partnership with several infrastructure providers, AES believes it can provide entire value chain solutions including LNG supply, logistics, design, build, commission and start-up of an LNG receiving terminal. AES operates in 15 countries so it could extend its model beyond the Dominican Republic and Panama. The question is whether it can negotiate price and credit terms that can support project financing of fuel switching its current power generation assets and underwrite a new liquefaction plant.

Independently of AES, Crowley Maritime through its subsidiary Carib Energy since 2013 has been supplying LNG to Coca-Cola Puerto Rico Bottlers in specially designed vessels, providing technical solutions include customized regasification systems; design services; mechanical, electrical and site/civil engineering; commissioning; storage and supply management; consultation and training; bunkering; providing a lower cost energy source, utilizing the cold from regasification to chill its products and even capturing CO2 exhaust gases to provide the fizz for its sparkling drinks.

  • S. Midstream Growth: Dominion Energy, Sempra and KMI saw LNG plants as a natural extension of their midstream pipeline businesses, but shareholders have been less enthusiastic:
    • Dominion Energy, a large electricity and natural gas company has shipped its first cargo from its Cove Point LNG plant with natural gas supplied by Shell and has 20-year sales contracts with Japanese and Indian buyers.
    • Kinder Morgan in 2015 bought out Shell’s interest in Elba Island LNG but Shell remained committed to supply natural gas and purchase all the plant’s LNG production; KMI then in 2017 sold 49% of its Elba Island LNG project to a private equity firm EIG as a “strategic step towards achieving our stated goals of strengthening our balance sheet and positioning the company for long-term value creation” according to Steve Kean, KMI President and CEO.
    • Sempra LNG & Midstream (SLM) is a subsidiary of Sempra Energy, whose main businesses are Southern California Gas; San Diego Gas & Electric; Oncor Electric Delivery and Sempra South American Utilities. SLM is a partner in Cameron LNG in Hackberry, LA with Engie, Mitsubishi, Mitsui and Japanese shipping company MYK Line. The project is under construction, with expected completion in 2019 though the capacity is not yet fully contracted.

Midstream companies are generally unwilling to take commodity price risk and seek a tolling agreement for liquefying the natural gas with a counterparty that has strong credit, leaving the buyer to take any price risk. U.S. midstream companies are quite uncomfortable with any deviation from the contracting model inherited from gas pipeline developments.

AES and Crowley Maritime are making a useful contribution by enabling fuel switching in end-user facilities, but so far on a small scale with a business model that currently depends on low spot LNG prices. Engie, however, with a footprint in 70 countries, may have more upside potential.

Tellurian is taking most of the commodity price risk in its newly acquired production subsidiary. Tellurian recognizes that the variable costs of natural gas production are quite low, where the capital costs are small relative to the cost of liquefaction. By buying producing acreage in the Haynesville, they can absorb periods of low end-user prices through a reduced return on investment in its production subsidiary and hopefully can compensate investors with superior returns during an up-cycle. They can also modulate their own returns on investment in liquefaction during the price cycle.

However, the Tellurian approach would not be necessary if large natural gas producers (e.g., EOG Resources, Apache and others with assets in the Permian and Haynesville plays) come to recognize that they are likely to achieve better netbacks to their wellheads by negotiating long term contracts with LNG developers including price formulae that incent international substitution of oil by natural gas.

Proposed Collaborative

With a plentiful supply, barriers to continued growth in demand and reluctance by traditional buyers to commit to long-term contracts required to finance needed infrastructure, new projects will be stranded. We propose a new model (Figure 6) that may be difficult to negotiate but would spread the risk among entities which in aggregate should have sufficient credit to support project finance.

Figure 6: Schematic of Hypothetical Collaboration Relationships


In our view, natural gas producers are the primary medium-term beneficiaries of expanding the global LNG market by encouraging fuel switching from diesel to natural gas. By securing new markets on long-term contracts, producers will eliminate the need to sell at sometimes distressed spot prices and will strengthen the overall market by increasing global demand. End users should also reap strong benefits of improved air quality, lower carbon emissions and lower costs.

  • Natural gas producers should be prepared to commit a proportion of their production to long-term reserve-backed contracts with emerging LNG markets at prices related to the oil products that are being substituted.
  • End users and their stakeholders should benefit from lower costs and improved air quality by switching from diesel fuel to regasified LNG.
  • Providers of equipment needed to switch from oil to LNG should be prepared to lease the equipment and provide ongoing maintenance at fair prices, rather than trying to sell the units at prices that the end user would find difficult to finance.
  • A shipping agreement for small used LNG tankers should be negotiable at favorable rates.
  • A liquefaction agreement could be negotiated with “ceiling and floor” features that allows the developer low returns on investment when netback prices to the producer are below Henry Hub spot rates but delivers superior returns when netback prices are above spot prices.
  • The “fixed price” construction agreement with the EPC contractor could also provide upside when netback prices are favorable.
  • By repeating the same model to various end users in various countries, country risk can be reduced.

This arrangement should spur expanded LNG demand from end users who might not otherwise switch from oil and aggregate credit strength to allow project financing and FID (Final Investment Decision) of the fuel switching and liquefaction construction projects.

The primary economic driver is the current and expected future gap between oil and natural gas prices. Google has recently compiled a database of power plants, listing nearly 3,000 globally (other than China) that rely primarily on oil as fuel.

Figure 7: South and Central Americas Power Plants Using Oil as Primary Fuel (Top Capacity Quartile)


The natural targets for switching to LNG may be in South and Central America (Figure 5) where there are close to 100 oil-fired power plants greater than 80 MW in capacity. The IEA estimates worldwide oil use for power generation in 2016 at 275 million tons of oil equivalent (over 5 million barrels per day) so the potential market is large.

Perhaps over time, LNG penetration may happen organically, but it is important to recognize the high inertia for change. The schematic we propose will be difficult to negotiate, but the alternative absent a catalyst to overcome inertia is a bust period of low LNG capacity growth as good project ideas are stranded, coupled with depressed U.S. natural gas prices. LNG supplies will then fail to meet demand growth ultimately leading to a commodity boom with higher LNG (but not domestic natural gas) prices leading to stifled global LNG demand growth and frustrating low cost domestic natural gas producers.

It’s an appropriate time to look for innovative ways to accelerate creditworthy LNG demand growth in the medium term. Our hope is that this article will stimulate some productive conversations.

Chris Ross is an Executive Professor of Finance at the C.T. Bauer College of Business, Gutierrez Energy Management Institute (GEMIand the University of Houston, where he teaches classes on strategies in the oil and gas industry. He also leads research classes investigating how different energy industry segments are creating value for shareholders. Ross holds a Bachelor of Science in Chemistry from King’s College at the University of London and a PMD from Harvard Business School.

Justin Varghese is a Spring 2018 Professional MBA graduate from C.T. Bauer College of Business at the University of Houston. He currently works as a project manager for Siemens and specializes in solutions for the oil and gas industry. He holds a Bachelor of Science in Industrial and Systems Engineering from Texas A&M University in College Station.

Calling Generation Z: The Energy Industry Reaches Out To Its Future Workforce

by Dr. Heather Domjan, Interim Executive Director, University of Houston STEM Center

The energy industry is engaged in a tug of war – it sees itself as playing a crucial role in helping mankind, while many Americans possess a deep-seated mistrust of oil and gas companies. That’s especially true of today’s school-age students.

According to Gallup, almost half of Americans (47%) had a negative view of the oil and gas industry in 2015, while just more than one-third (34%) viewed the industry positively. By 2017, the gap had narrowed, but negative opinions still topped positive ratings by 2%.

2017 Business & Industry Ranking Net Positive Scores

Public opinion has dampened energy companies’ ability to overcome misconceptions and differences in opinion. And young people may be their toughest audience, at a time when the industry is facing a growing demand for new workers.

Generation Z’s Perception:

Here’s the storyline for America’s youth:

  • Coal was the fuel for their grandparent’s lifetime
  • Oil and gas was for their parent’s generation, and
  • Renewable energy is the future.

This should be a wake-up call for the industry, which must make members of Generation Z – definitions vary, but generally those between 2 and 19 – a priority, as these individuals have the ability to shape the future of energy through innovation. The complexity of this task becomes clear when you realize this generation may hold beliefs that are not necessarily substantiated by facts, contributing to the divide between supporters of the oil and natural gas industries and those whose concerns about climate change and the production of fossil fuels push them toward renewable energy.

EY  last year surveyed U.S. consumers and energy industry executives about current perceptions of the industry with striking results, especially among teens. Generation Z described the industry as a “problem causer, rather than a problem solver.” More than half of teens – 56% — said the industry isn’t worth the damage it causes to the environment. Media coverage of oil spills and other accidents become ingrained in the minds of these young people and, over time, they have developed a one-sided mindset.

Teens are digital natives and when only 44% deem the energy industry a leader in technology and 41% consider it “innovative,” clearly there is a disconnect. Only 45% of teens surveyed said the industry is trustworthy.

It is difficult to overcome these negative images, especially when only 35% of teens believe your industry will be important for another century.

US perceptions of the oil and gas industry survey, 2017

This disdain may originate from embedded misconceptions developed through exposure to various media. Young people want to find solutions to climate change, display responsibility through “green” actions and showcase their consumer power by using the premise of renewable initiatives to speak to government and industry regulations.

But these young people can miss the nuances of an argument. For example, teens often fail to note that although renewable energy is considered “clean” because solar and wind power don’t themselves generate greenhouse gases, it has other drawbacks, including that it is a variable source of energy, available only when the sun shines and the wind blows. Therefore renewable energy currently is usually supplemented with fossil fuels to meet consumer demands.

The insights from the EY survey should capture the industry’s attention, especially considering they are already up against the wall of time, with one-third of the energy workforce at retirement age.

So how can industry overturn this perceptional tide among young people? It has begun to fight back.

Energy Industry Response:

Investing in K-16 students – that is, those from kindergarten through higher education – is vital, but how can oil and gas companies obtain a return on their investment when identifying what action best works can takes months or even years?

Even with so many education programs encouraged and funded, in part, by the industry, Generation Z remains skeptical.

Time is of the essence for industry to re-evaluate its stance within K-16 education and make a calculated effort to ensure students are exposed to valid points on both sides of the discussion to debunk any falsifications. The industry must step up its efforts to collaborate with educational experts to forge a united front that ensures the message of transformative energy is appropriately delivered.

Social interaction will be key, too, recognizing that Generation Z will be tomorrow’s decision makers about critical energy issues. Students are exposed to many opinions as they surf the web’s turbulent waves , and if the energy industry is to get buy-in, it must continue to be visible.

There are options. A massive career awareness media campaign highlighting the variety of jobs within the industry could expose students to the possibilities. When was the last time you saw a commercial about careers in the energy industry?

Oil and gas companies are investing both money and manpower in America’s youth, but will the effort be enough to overcome the views Generation Z currently holds? Oil and gas companies invest in initiatives such as STEM programs and competitions that emphasize science, technology, engineering and math skills, diversity outreach, educator support, career awareness campaigns and community engagement. In Houston, home to dozens of both majors and independent energy firms, and elsewhere, company employees are encouraged to volunteer with schools as mentors and guest speakers.

Only time will tell; however, energy industry executives must remain in the game so college-bound students will consider the industry with confidence.

Dr. Heather Domjan is the Interim Executive Director of the University of Houston STEM Center as well as a clinical assistant professor in curriculum and instruction. She instructs classes on science pedagogy to future educators with a focus of science, technology, engineering, and mathematics. Dr. Domjan also serves as the Executive Director of the Science and Engineering Fair of Houston which is one of the largest STEM events in Texas.

UH Energy is the University of Houston’s hub for energy education, research and technology incubation, working to shape the energy future and forge new business approaches in the energy industry.

Amnesty and New Violence in the Niger Delta

by Rebecca Golden-Timsar, Associate Director, Graduate Certificate in Global Energy, Development & Sustainability (GEDS), University of Houston

Hoping to quell a violent insurgency aimed at the Nigerian government and the oil industry in the Niger Delta, the Nigerian presidency implemented an unconditional amnesty in 2009, offering a clean slate to militants whose demands for resource control, environmental justice and sustainable socioeconomic development had resulted in massive regional disruption.

I have been conducting research in the Niger Delta for the past 20 years, and my latest trip there in early 2018 found ample evidence that the amnesty hasn’t worked as planned. The negotiated amnesty and resulting fragile peace are primed for collapse, while crime and oil theft remain serious problems.

Then-President Umaru Musa Yar’Adua introduced the Presidential Amnesty Program, (PAP) or the Niger Delta Amnesty Program (NDAP), as a disarmament, demobilization and reintegration program to answer to the increasing violence throughout the prior decade, which intensified after Ogoni environmental rights’ activist Ken Saro Wiwa was executed by a military tribunal in 1995.

The amnesty was originally designed to last only five years, but it remains in effect.

In the 18 months leading up to the 2009 amnesty deal, world crude oil prices topped $145 per barrel while the insurgency compromised Nigeria’s production capacity by 900,000 barrels per day (about 30% in 2007), which dramatically impacted the national treasury. Although the amnesty precipitated a cessation of hostilities against the federal government and the oil industry, the results are fraught with the makings of new violence.

Approximately 30,000 people in the Niger Delta enrolled in the PAP as ex-militants. However, only 2,700 weapons were surrendered. Some militants, fearing the program and its potential repercussions, abstained from participating. I found three potentially explosive problems with the amnesty as it relates directly to reintegration of ex-combatants: reinforcement of militant hierarchies and commodification of violence; substitution of militancy for criminality and ongoing communal tensions; and professionalization of illegal oil lifting of Nigeria’s current production.

Reinforcement of militant structures and organizations

Under the agreement, former combatants were promised monthly stipends and job training. But the payment system is hampered with challenges. The extended duration of the payments – almost 10 years – and the methods by which they are distributed reinforce militant hierarchies rather than dismantling them and helping to reintegrate the former militants into society. At the outset, the federal government of Nigeria reportedly made lump sum payments to ex-commanders, who were charged with distributing the cash to their ex-combatants. This system was challenged in 2015 by mid-level commanders claiming corruption in the payment system and in the granting of large pipeline security contracts to top commanders, with little trickle-down effect.

A new system was devised to directly deposit the payments to the former combatants’ bank accounts. But this was also challenged by the ex-militants, who accused commanders and the banks charged with the distribution of collusion and shortchanging payments. The lump sum cash payment system was resumed in 2017.

This is problematic on several levels. First, paying ex-commanders directly maintains fighting organizations and power structures. The continued amnesty payments reinforce patronage networks. They also create vehicles for political power and political violence for the 2019 presidential elections.

Finally, the stipends have morphed into a cash-for-peace system that is not sustainable, turning violence into a commodity.

Exchanging militancy for criminal behavior and community tensions

The top-down cash distribution creates and re-creates potential rivalries through discretionary and often opaque cash disbursements. By bolstering ex-commanders’ control, the former fighting organizations are re-created and able to leverage their power over the government.

This has resulted in fresh threats and eventual attacks on the military, oil installations and hostage taking, with direct consequences on oil production at a time when lower oil prices have already affected Nigerian coffers.

When stipends were not paid for several months in 2016, ex-combatants quickly slipped into old patterns of resistance as ‘new’ groups that emerged. The Niger Delta Avengers, Red Scorpions and the Niger Delta Greenland Justice Movement all rose in 2016, attacking the Forcados pipeline installations  in the western Niger Delta, causing national production to plummet to a 30-year low at 1.1 million barrels per day. After payments in arrears were made, these groups fell somewhat silent again.

Further, because of the relatively significant amount of monthly individual stipend, ex-combatants are discouraged from getting a job, which even for professionals, generally pays less than the amnesty stipend of 65,000 Naira per month, equivalent to about $180 in U.S. dollars. An average schoolteacher in Nigeria earns 18,000 Naira, or about $50.

The sizeable stipends, coupled with limited access to and availability of skills training under the amnesty agreement, the lack of fundamental improvements in regional socioeconomic development and increasing small arms circulation, only serve to sustain the fighting frameworks and capabilities to strike. Consequently, concepts of the marginalized warrior identity, fundamental to the protracted violence, are also sustained.

Because there haven’t been sufficient sustained reintegration efforts in the way of training and job creation, there is an increasing perception of criminality in the Niger Delta, and particularly in the oil capital, Port Harcourt. Reports of the kidnapping of prominent locals and their family members abound, as do reports of increased armed robbery. Additionally, former combatants continue to turn to gang (known as cults or campus cult organizations) membership, creating altered if not new layers of communal rivalries as these gangs battle for turf.

Further, the amnesty program’s lack of full participation from some commanders and their militants, along with the limited surrendering of weapons, generates additional communal rivalries and violent clashes, both between and within militant and gang hierarchies.

Illegal oil lifting

Finally, illegal oil lifting (known as bunkering) has been increasingly professionalized and militarized: there are organized underground labor unions for both crude and refined products; there are well-defined levels of investment for buy-in for the lifting and marine transport activities from the pipeline tappers, pumpers and speedboat drivers to offshore tankers, captains and document forgers; there are set payoff calculations for the players including the Nigerian military’s joint task force; and security details for each phase of the operation.

Current bunkering estimates range from 10% to 15%, or a minimum of 200,000 barrels per day (roughly the total production of Trinidad) out of the official production rate of just over 2 million barrels per day in early 2018.

Despite the decreased hostilities ushered in by the amnesty, Niger Deltans report that since the inception of the amnesty, the federal government’s military presence has broadened rather than diminished. They blame the military and the politicians that control it for the majority of the bunkering activities and for generating the conditions for the current reciprocal racketeering.

The outcome of the military presence, the ongoing militant hierarchies and poverty serve to maintain a social disorder and a security economy-potent ingredients for petrol violence anew.

Eyes in the Sky Offer a Dramatic Picture of Energy Use

by Ryan Kennedy, Associate Professor of Political Science, University of Houston

Some readers will remember the dramatic change that took place with computer access in the 1980s and 1990s. Computers were once large machines, which took entire rooms to themselves and were only available to major corporations, government organizations and universities. This changed dramatically in the 1980s with the introduction of the personal computer. Much smaller machines, still capable of doing advanced computations with what, for the time, was amazing speed.

Today we may be experiencing a similar revolution, but this time with satellites, and this revolution will have important implications for the energy industry. Two interrelated trends are driving this. First, governments and corporations are opening up the data collected from their satellites for public use. One of the most popular examples of this is the Night Lights dataset, provided by the National Oceanic and Atmospheric Administration (NOAA). Originally used to detect cloud cover for military usage, NOAA now makes available a global map of the world as it is lit at night – producing dramatic illustrations of global energy usage, like the map of North and South Korea below.


The second trend has the potential to be even more disruptive. Much as the microprocessor allowed access to computers for the masses, the development of picosatellites – small, low-cost satellites that could be used for a variety of purposes – have the potential to do the same for satellites. Planet, for example, is a private company that utilizes a chain of satellites constantly orbiting the earth to collect high-resolution pictures of the planet at all times. From this information, they design computer algorithms to monitor supply chains, natural disasters and a variety of other metrics that may interest other companies. Everyone from NASA to SpaceX is now trying to encourage the development and deployment of smaller and smaller satellites that can do everything from monitoring pollution to creating an artificial meteor shower.

The explosion of satellite data has large potential impacts on research and policy in the energy arena. Eugenie Dugoua at Columbia University, Johannes Urpelainen at Johns Hopkins University’s School of Advanced International Studies and I approached a specific application of this satellite data in our forthcoming article in the International Journal of Remote Sensing. We used the data from the Night Lights dataset to explore the extent to which it could be used to track electrification patterns among villages in rural India. This was the largest attempt to validate the data on a sub-national level, and our results suggested satellite data could be used with reasonable success to track the progress of rural electrification throughout India.

This suggests policymakers can use such data to gain nearer-real-time monitoring of the progress of their policies, without having to wait for the next census.

There were, however, some caveats. First, we noticed that the capability of the satellite data to capture the development of rural electrification was conditioned on the methods used for analysis. In particular, the performance depended greatly on how good the available geographic information was for the actual shape of the village. Second, we noted that the capability of the satellite data to detect electrification was conditioned on the steadiness of the regional electricity supply. This suggests satellite data works better in areas that are more developed and have access to high quality connections. Finally, even though some scholars have used Night Lights to detect the level of economic development for regions, we find that it is not a very strong indicator in rural India, where the government has made a strong push to electrify poorer villages.

All of these findings suggest some areas about which policymakers and corporations need to be aware for the upcoming satellite revolution. While satellite data can do a lot for us, the ability to develop good proxies for events on the ground still depends on our ability to directly capture the relevant comparison information. Satellite data may not replace traditional monitoring, but it will likely provide a way to get data more quickly and cheaply between traditional data gathering periods.

It also provides a warning about the limitations of satellite data collection. Careful validation is crucial for understanding what the satellites are actually capturing with their images and making sure the data means what we think it does.

Much like the hype about “Big Data,” managers should beware of latching onto this data before its utility has been established.

We must also be aware of the context around the data collected. As we found, policies intended to electrify poorer villages undermined the ability for us to use the satellite data for measuring economic wellbeing, since some villages gained electricity access exactly because they were underprivileged. As with any data source, we need to have a clear understanding of the process that generates the data we observe.

We are moving into a potentially revolutionary era when it comes to the accessibility of data from satellites. With careful study and evaluation, this data can greatly assist corporations and governments as we attempt to purse policy goals and monitor how our world works.

Plastics Recycling: Could The Future Be In India?

by Ramanan Krishnamoorti, Chief Energy Officer, University of Houston

On a recent visit to India I made two striking observations:  First, in the smaller cities and on national highways, plastic bags were everywhere. Plastic pollution was rampant. Second, even as the Indian government’s pro-growth policy calls for the increased use of plastics – plastics are, in effect, a proxy for economic growth – the country’s plastics recycling industry is booming, spread across an informal amalgam of street pickers, small start-ups and non-governmental entities focused on the secondary use economy.

India isn’t alone in its efforts to deal with plastic waste. About 75 percent of plastic waste in the U.S. ends up in landfills, and less than 10% is successfully recycled. (Most of the rest is combusted for energy.)

Plastics are lightweight, versatile and durable but in spite of their ubiquitous presence and critical role in many of our technological advancements – from automobiles and computers to replacement heart valves – they are now seen as a challenge to animals, marine life and future generations of humans.

Recent reports of plastics and microplastics pollution in every remote corner of the oceans has raised public awareness of the challenges posed by our increased use of synthetic plastics. In some cases this has raised the call for more biodegradable plastics to replace synthetic plastics. However, a UN report in 2016 indicated that biodegradable plastics are not the panacea for the marine challenge of plastic litter in the ocean.

Even so, biodegradable plastics and those that are easier to recycle or repurpose will be important for reducing other waste streams, and science has responded.

A number of researchers are working on the problem. From the other end, a growing number of cities in the U.S. and Europe have banned single-use plastic bags. India, too, is struggling to deal with these ubiquitous carry-alls.

Some cities and regions of India have banned these ultra-thin bags – which are made of polyethylene, a non-biodegradable petrochemical product – and metropolitan areas and both some state and the national governments are focused on the difficult task of enforcing the bans.

India’s informal plastics recycling economy has instead focused on the more lucrative water and shampoo bottles, which are easier to gather and process and are far more lucrative than the lightweight bags. But the country also has spawned some of the most creative thinking about how to deal with this thorny issue.

And all of those efforts come amidst a government push to actually increase the amount of plastics in Indian society.

The average Indian uses approximately 25 pounds of plastics each year, about a tenth of what an average American uses. The Indian government has set the goal of doubling the per capita plastics consumption by 2022, presumably a surrogate measure for economic advancement and increased advanced manufacturing.

More plastic represents more wealth.


Figure 1  Per capita plastic products consumption (Kg/person) http://ficci.in/spdocument/20872/report-Plastic-infrastructure-2017-ficci.pdf

Recent estimates predict a 10% compound annual growth rate (CAGR) in plastics consumption over the next five years, reflecting a similar growth in the preceding five years. On the other, the local governments are responding to public outrage, including with the banning of plastic bags including ultra-thin bags of polyethylene and Styrofoam-based products. The national government is also considering banning polyvinyl chloride, or PVC, a plastic used in infrastructure building that, when improperly disposed of, leads to the release of toxic compounds into the environment.

That’s just one example of why India has long been called the land of contradictions. The country’s love-hate relationship with all things plastics is no different.


The street picker-based recycling economy, along with the various bans, have ensured India’s continued efforts in battling plastic pollution. At the other end of the spectrum, the country is home to some of the most innovative thinking about plastics recycling.  Clearly the economic and developmental goals of India, if not the world, require a fresh approach to changing the story of plastics.

That approach might be found here. Banyan Nation, a plastics recycling start-up from the Indian city of Hyderabad, stunned the world by winning the Dell People’s Choice Award for Circular Economy Entrepreneur as part of the Circulars Awards at the World Economic Forum in Davos.

The five-year-old company is known for its work with Tata Motors in recycling automotive bumpers and for working with the French cosmetics company L’Oréal to recycle shampoo bottles. But its true innovation lies in its efforts to address the three key challenges in plastics recycling in countries like India – addressing the “last-mile” of the waste through a digital network; developing a strategy for cleaning and sorting the plastic waste economically to ensure creation of a secondary-use pellet that was comparable to primary plastic; and lastly partnership with large state-wide entities and multi-national corporations towards the waste-to-product recycling for e-waste, automobile parts and consumer products packaging.

Such a systems level approach is perhaps the only way we are going to address the challenge of plastics pollution and ensure their continued use to fuel life-changing innovation across the world.