Leigh Creek Energy — Increased visibility on pre-commercial demo

SA has been at the epicentre of the Australian energy crisis, with gas and electricity prices at record highs. With 40% of SA energy generated by renewable sources, such as wind and solar, and a material increase in non-synchronous generation within the supply-mix, the grid has become more susceptible to shortages and the need for load shedding. Wind and solar have a lower inertia, which means the systems have a higher rate of frequency change and they are also an intermittent power supply requiring backup from storage or conventional sources of generation capacity.

SA has become increasingly reliant on its single interconnector to import power supply, the Heywood interconnector to Victoria. In recent months, the Heywood interconnector has incurred reliability issues when strained, leaving SA isolated from the national grid. Plans for a second interconnector to New South Wales have been discussed, but at a cost of between A$500m-A$1bn would prove to be an expensive solution and one still reliant on the availability of import capacity. The dependency on one interconnector and lack of competition in SA means it can struggle to meet demand. On 8 February 2017, wind could only produce 2.5% of the state’s electricity and, with the Heywood interconnector already at the maximum, the Australian energy market operator (AEMO) started load shedding as demand was too great. This left 40,000 SA households and businesses without electricity.

The final report by AEMO on the 28 September 2016 blackout highlighted the need for an assessment of safety features, and increased interconnectivity, local competition and synchronous generation. With ever-increasing use of renewable energy, the SA government needs to be able to access stored power or backup sources of supply in order to increase energy security.

The SA government announced in March 2017 a high-profile A$500m contingency plan to improve the supply of electricity, which has compelled a number of blue-chip power providers to offer solutions. This has included the likes of Tesla, which has been tasked with the role of building the world’s largest capacity and output lithium-ion battery. The battery will be able to store 129MWh and has a maximum output of 100MW. CEO Elon Musk himself said the battery is to be built in “100 days once the contract is signed, or it is free.” It is hoped that it can be built before summer and will be linked to a wind farm north of Adelaide.

Jay Weatherill, the Premier of SA, announced that the state government will lease a range of nine new portable diesel generators from APR Energy (APR). APR reported that it should be in place before 1 December 2017. After two years, the state will have the option to purchase the newest generation of GE TM2500 turbines and turn them into a permanent gas generator. They will produce 267MWh of power together and are expected to be under the budget of A$360m.

The battery and portable generators are not designed to drive down prices, but to reduce volatility and assist during peak times, mitigating the risk of blackouts and load shedding. Hypothetically, this should then reduce electricity prices as it reduces risk premiums incorporated in energy companies’ contracts.

The proposed gas generator and increased use of gas in turn poses its own problem. The government announced in March 2017 that there will be a gas shortage by 2019 in SA and other states could be affected by 2020. It has since reduced its risk level due to new proposals from Arrow for a major expansion with new wells and pipelines to double production at its Surat Basin site, as well as the option to redirect some exported liquefied natural gas (LNG) to domestic supply. There remains tension between the federal government and the SA government over the energy crisis.

Australia was the second-largest exporter of LNG in 2016 and has neglected domestic supply, causing prices of electricity and gas to increase year-on-year. Last month, the three main providers – Origin, AGL and EnergyAustralia – all announced increases in gas and electricity of up to 20% for retail customers. They have blamed the increase on wholesale gas and electricity prices.

On 10 July 2017, LCK announced it had assigned two construction contracts, after an intensive tender process supported by the SA government. The first contract with Ottoway Engineering will provide LCK with bespoke gas handling equipment for the PCD to take gas from the underground gasifier to the thermal oxidiser. The scope of the contract is the fabrication and installation of the above-ground plant for piping, knock-out, metering and condensate handling skids. The second is a contract with ATSys, which will provide electrical, controls and high-end communication and data transfer systems for the PCD.

It was announced at the quarterly update on 28 July 2017 that LCK had awarded a further two contracts to Gasco and ABB Australia (ABB). Gasco won the contract to supply the thermal oxidiser and cold vent. The thermal oxidiser combusts syngas at high temperatures and the cold vent is a safety measure to release the pressure in the result of a blockage. ABB has been awarded the contract to supply the gas analyser and gas instruments. This will analyse the Syngas composition for commercial considerations. LCK is yet to award contracts for the generator, diesel storage and water tanks, but has already secured funding.

LCK has received the first two tranches of financing from CNE and the third and largest tranche of A$12.5m at A$0.15 per share will be subject to a shareholder vote at a general meeting in September as it will increase CNE’s stake to greater than 20%. Having obtained A$9.3m of funding from the first and second tranche, the LCEP is accelerating quickly and it is anticipated that plant fabrication of the PCD will be installed in November 2017. The total amount raised will be A$21.85m, before fees with an average share price of A$0.146. LCK remains on track to be fully funded for the completion of PCD, through tranche three and continued access to the Commonwealth Bank of Australia R&D working capital debt facility.

Core elements of our valuation of LCK are provided in our initiation note (2 February 2017). We recently updated our valuation to reflect equity funding for the company’s ISG demonstration project and a delay of LCEP first gas to 2021 (compared to 2020), offset by a roll-forward of our NAV discount date from 2016 to 2017. We flag that this is based on a subjective 20% chance of commercial success and assumed farm-out of the upstream full field development. Further details of gross project economics and farm-out assumptions can be found in our initiation note.

A sensitivity to our chance of success assumption (20% base case) is provided below. The market implied chance of success, post equity dilution, currently stands at 12%.

In addition, we recognise that there will be several phases of de-risking as the LCEP project progresses through successful demonstration, full appraisal, environmental permitting, full-field development funding and partner alignment. We attempt to demonstrate this de-risking and the potential impact on valuation in Exhibit 8 below.

At the current share price, LCK offers investors an option on realising value from ISG in South Australia. LCEP has what appears to be an optimal site for an ISG project in a state with a need for additional baseload power capacity. The project does not come without technical and commercial risks; however, we expect technical and environmental aspects to be materially de-risked through the company’s upcoming pilot programme in 2017.

The remaining net cost of LCK’s ISG demonstration project including operational spend is estimated at c A$16m and is expected to be funded through the company’s recently announced equity funding round of gross proceeds of A$21.85m.

Our LCK financial forecasts do not reflect LCEP first gas until our modelled start-up date of early 2021; however, we see potential for this to slip as the first gas from demonstration is now expected by end 2017. In our base case forecasts below we assume LCK is cost-carried for its portion of LCEP capex costs prior to first gas, hence there is minimal capex beyond 2018 in our financial forecasts. The availability and cost of farm-out funding is an investment risk – further details of which are provided in our recent initiation note.