PTQ Q2 2023 Issue

the centre. Whether a firm or an investor is focused on finan - cial or ESG measures, doing this well, aligned with each firm’s goals, is critical in securing access to the cash required to realise their vision. With carbon, we want to put the right molecules in the right place. This can be the right process unit or separating the right product pool. With hydrogen, we want to optimise the sources and uses – put it on to do good things, take it off to do good things, and do that as few times as possible. With utilities, we want to do more with less and minimise utility usage. When we are successful with utilities, emissions also come down. But emissions can also be favourably reduced when we employ the proper molecular management and drive towards smaller equipment to carry out the objectives. Water is critical. We want to treat water as a scarce resource because it is. There is a growing competition for water between civil, social, societal, agricultural, and other industrial uses. We need to minimise new water consump - tion and strive for zero water discharge. Finally, it must be noted that the approach to securing capital has shifted dramatically over the past few years. Large banks have shifted their lending profiles towards green projects (see Figure 2 ). Financial portfolio manage - ment is extending beyond traditional measures, such as net present value (NPV), internal rate of return (IRR), and debt service coverage ratio (DSCR), and increasingly focusing on sustainability measures, such as CO2 per tonne of product and CO2 per dollar invested. Boards of directors are also driv - ing this proliferation. As this communication cascades down organisations, project managers at the individual site level are increasingly asking us to help them achieve the financial measures, but also the ESG measures. Scope 1, 2 and 3 emissions Scope 1 emissions, commonly known as direct emissions, are produced as part of day-to-day business. These include emissions exiting process units and heater stacks, emissions from on-site generation of utilities, fugitive emissions from flanges and valves, and company vehicle emissions. Scope 2 emissions frequently are referred to as indirect emissions. These are associated with the generation of energy needed to run a facility that is produced by and pur - chased from someone else. Scope 3 emissions arise primarily from the ultimate com - bustion of fuels that a refinery produces and sells. Scope 3 also includes emissions associated with disposing of waste streams and emissions generated when others fabricate, manufacture, and deliver such things as catalyst, specialty equipment, vessels, exchangers, and pumps on the facil - ity’s behalf. Scope 3 encompasses everything upstream and downstream of the facility, making this the largest compo - nent of its carbon footprint. There are several ways an existing enterprise can reduce emissions. These range from low-cost tactical ‘just go do’ activities to the most strategic shifts, such as pivoting from fuel to petrochemicals production. No- or low-cost solutions include reducing slops reprocess - ing, reducing or eliminating flaring, and avoiding over-reflux - ing columns. These can often be solved through visualisation

$50B

Fossil fuel industry

Green projects

$10B

2015

2019 2020 2021

2016 2017 2018

J P Morgan

Wells Fargo

Citigroup

B of A securities RBC Capital Markets

Note: Includes top ve largest lenders to fossil fuel industry since 2016 Source: Bloomberg league tables

Figure 2 Greening of the big banks

tools to quantify processes and understand how to get the most out of their assets every day, across every shift. At a slightly higher cost, operators can consider using higher activity catalysts. These reduce reactor temperatures, leading to a reduction in the amount of fuel used and a subse - quent reduction in the CO2 footprint. Operators can optimise pump efficiencies by properly sizing impellers and control valves or improving the compressor anti-surge control sys - tem hardware, software, and programming. Moderate- to high-cost options might include adding to the heat exchanger network, optimising hydrogen and electrifica - tion networks, monitoring and mitigating fugitive emissions, and replacing exchangers with higher efficiency systems. When we engage with the customer to start this journey, we start with a Concept Development Workshop – effectively a voice-of-the-customer exercise where we align our listen - ing skill set to understand where the firm wants to transition or improve across time. It helps us identify the right ideas to assess. Then, working with the current value of carbon in the global region, we create a carbon abatement curve for the customer, in which carbon reduction opportunities and their CO2 impact are paired with the cost per tonne of CO2 reduced. This provides a roadmap through which a firm can plan its journey. Cost of hydrogen production drives regional technology selections The cost to produce hydrogen varies from region to region around the globe and has a profound impact on the types of technologies employed and market participation. For example, the cost of hydrogen in China out of a steam meth - ane reformer (SMR) is approximately $2,000/t compared to $750/t in the Middle East. As a result, China drives crude oil to aromatics projects; when they search for olefins projects, they end up importing propane (effectively as a hydrogen source) to feed their propane dehydrogenation units. Lower energy prices result in a cost advantage for produc - ing light olefins in the US, the Middle East, and places that have a similar cost structure, while places that have a high hydrogen cost structure (China, SEA, India) are looking more towards aromatics production and/or imported feedstocks.

PTQ Q2 2023