Liquefied Natural Gas Ltd — Update 26 April 2016

Investors have seen LNGL shares fall materially since the peaks seen in May 2015. We attribute this to a number of factors:

As can be seen in the charts below, there is a very strong relationship between the shares and the oil price, with an R2 of more than 0.85 since May 2015.

We attribute this relationship to investors linking the value to the chance that the projects reach project sanction and to the eventual EBITDA margin captured by the projects. We believe that both are heavily related to the underlying LNG pricing that LNGL’s prospective tolling partners believe they will be able to achieve. LNGL is running long-term projects, for which the short-term oil price is not as important as we believe investors attribute it to be.

LNGL has tracked Brent in a similar way to other peers, so is not alone. General market sentiment has fallen, taking many companies with it. Cheniere Energy, Golar LNG and Kinder Morgan have all been victims alongside LNGL. It is worth noting that although the correlation with the oil price has been to a high level in the past, the degree of this correlation (as measured by R2) was particularly strong in 2015 (see Exhibit 4).

While the headline Brent pricing may have seen good correlations with the share price in recent months, it should not necessarily be the best guide to the future value of the company. Once the project is running, the company’s value should be independent of LNG or gas pricing (assuming a purely tolling agreement model).

Until then, it is clear that investors are using the oil price as a proxy for long-term confidence in LNG/energy demand, which itself may be seen as a measure of confidence in the project going ahead. Should investors want to see relationships between oil, gas pricing and LNG realisations, we calculate a forward price for LNG margins based on the differential between Henry Hub and Japanese LNG pricing (with forward movements based on movements with Brent 30 days previously). This shows that the LNG margins have suffered more than Brent, mainly despite Henry Hub prices moving down in recent months.

In the longer term, LNG pricing should recover and increase to a greater extent than Henry Hub pricing, providing more robust LNG differentials for LNG traders. On these data, the differentials are unlikely to reach the levels hit in 2012, but we believe margins of around US$5/mmbtu are not at a level to allow LNGL’s tolling partners to make profits. Thus the differentials will have to expand from the prices implied by this analysis if any future US-based LNG projects are to be justified.

Over recent months, LNGL signed a lump sum turnkey contract with KBR lead KSJV and set up strategic alliances with Siemens, Chart and EthosEnergy. These set clear benchmarks on costs for the project, with targets for contractors to complete work on time and on budget. Further clarification on “other costs”, including ramp-up gas, insurance, O&M fees and others, have also been clarified and set. These add up to a materially larger capex bill (see later section), but give a far greater confidence in the new estimates and involve a number of marquee names.

The contract was summarised by LNGL as follows:

An excerpt from the FERC website (in Exhibit 7) gives an idea of the progress of Magnolia through the regulatory process. On 18 April, the company received the FERC order, step 17 of 20 in the regulatory cycle. As a result, only a few steps remain before the Notice to Proceed.

We note that the milestones achieved are still high and do not show a number of the important steps that have also been taken. These include the Schedule for Environmental Review, and submission of the Draft Environmental Impacts statement (DEIS) and the Final Environmental Impact Statement (FEIS). Progress made on non-FTA status is also excluded.

The project is awaiting a number of major final milestones before financial close. Until these are complete, the company has put the EPC and related contracts on hold to minimise cash burn, while enabling the projects to ramp up quickly once all the pieces are in place.

In particular, we would highlight the following

We have made a number of changes to our modelling, given recent newsflow and developments.

Increased capex: we have firmed up our capex estimates following the announcement of the contract, moving capex to US$4.4bn for four trains (two phases). This is a significant increase from our last assumptions, but the project lies on a firmer basis with higher guaranteed volumes (7.6mtpa, 0.8mtpa greater than previously). The cost per ton remains at the lower end of global projects, so should still be attractive to LNGL’s tolling partners looking for commercial advantage.

The additional cost does bring the funding of the development into greater focus. Even with debt funding doing the majority of the heavy lifting (and with Stonepeak’s contribution helping), the additional capital investment required means that LNGL will need to find equity funding of its own for the project (most probably for trains three and four). This may come from an additional equity partner in the Magnolia project itself (perhaps as part of a deal on the offtake) or at group level. However, shareholders are likely to see their existing holding in the project reduced to fund it. On a non-discounted basis, this shortfall amount totals around US$200m by 2019 for Magnolia (although this will depend on the tolling fees achieved and the equity LNGL retains as a result). In our valuation, we account for this cash shortfall by taking the NPV10 of the capital in the projects and applying a 15% cost of equity.

The addition of a success/production payment to the contractors was not something we had previously assumed. The payment of $0.07/mmbtu for production means cash outflow of up to US$30m per year from the project.

Increased revenues/EBITDA: we had previously anticipated EBITDA of US$2.00/mmbtu, as guided by the company in 2014. This has increased following the realisation that higher capital costs will require higher fees to achieve required rates of return. An analysis of peer projects indicates that US$2.75/mmbtu would still be at the lower end of the peer spectrum and should still encourage investment by tolling partners. However, recent market changes are likely compressing margins and we expect that tolling partners will require lower charges to make returns for their trading operations. For the moment, we assume a US$2.30/mmbtu margin, but are aware that there is notable uncertainty in this expectation.

We retain a tax rate of 38% (although in the fullness of time this may turn out to be too low as the company may be able to negotiate state tax breaks).

Debt financing: we had previously estimated that 70% of the project would be debt financed. We have increased this to 75% as the plants from Freeport LNG and Cameron LNG have reportedly achieved this level. IHS CERA has estimated that since 2000 LNG projects have on average used debt financing of 71% since 2000. The project will have low political risk (being in the US), although the new application of technology may require a small risk premium (albeit this should be offset materially by the EPC guarantee volumes). Looking at Exhibit 11, we would expect this percentage to need revision if the project is not fully derived through long-term contracts.

We continue to assume a debt cost of 7.5%, but note that the rate arrived at will have a material impact on the project, given the high percentage of debt funding. A 1% increase in this rate would decrease the total project NPV by c 4%. Given Stonepeak’s fixed return, it would have a greater impact on LNGL’s equity stake.

These factors result in a lower NPV for LNGL’s stake: the increased equity investment from Stonepeak and the higher capital investment for the project results in a lower NPV.

We have taken the opportunity to push Bear Head further into the future. While the project should be strongly value accretive for LNGL, the development process has not been as fast as we had expected and has delayed our timelines. A clear line of sight to gas supply is required before tolling partners can be brought in. However, the state of the site and progress on permitting (including a recent authorisation from the US DOE for gas exports to the project) should enable swift progress on the project once gas supply is secured. We note that options for gas supply remain either sourced from the Marcellus Shale in the US or from discoveries/prospects offshore Nova Scotia.

On 8 February, the US DOE issued final authorisation for Bear Head to export LNG derived from US-produced natural gas to countries without free trade agreements with the US. Bear Head is now the first and only proposed Canadian LNG export facility to obtain non‐FTA authority and all the initial regulatory approvals to commence project construction, with approvals achieved in less than 12 months. The DOE also declared that no permit was required for any Canadian gas to go through US pipelines in transit to the site.

These elements remove a key risk for the project and its ability to source gas from a range of sources. Currently, we assume that gas will either come from onshore gas supplied from the US (probably shale gas from the Marcellus) or from offshore Nova Scotia. These permits now clear the way for the project to source from either of the sources and export globally, which should increase the attractiveness of the project to both tolling partners and potential equity partners.

On 4 April 2016, LNGL announced that Maurice Brand, founder and long-time MD, was stepping down. He is to be replaced by Gregory (Greg) Vesey, a professional with 35 years’ experience at Chevron where he was responsible for global gas marketing and trading activity including extensive LNG development work. His previous appointments covered the introduction of new technology, international operations and included commercial and execution responsibilities as well as liaising with stakeholders. Maurice Brand will continue as an executive director (based on his existing Employment Agreement) until his retirement by June 2017.

On 20 November 2015, LNGL announced the appointment of Anthony Gelotti as chief development officer based in Houston, Texas, US. He brings a wealth of experience from Chevron LNG supply and trading.

LNGL also announced that Mr John Baguley, chief operating officer for Magnolia LNG will assume the additional responsibilities of LNGL’s chief technical officer. John, who is based in Houston, replaced Mr Paul Bridgwood, who wished to remain in Perth and left the company on 30 November 2015.

On 18 August 2015, LNGL announced the appointment of Ms Kinga Doris as general counsel and joint company secretary, based in Houston, Texas, US.

Following the changes to modelling, our valuation for the company falls materially. This is mainly due to the increased capex incurred at Magnolia (partially offset by expected increased EBITDA). We have not adjusted the riskings for the project, but note that Bear Head has been pushed out (even though non-FTA approval is a very encouraging step). This results in a NAV of A$1.0 or US$2.8/ADR, which is well above current market prices.

We employ this DCF-based approach given the pre-cash flow stage of the company, but would expect the shares to trade on an EV/EBITDA or P/E in line with peers as first cash flows approach. We note that infrastructure/utility-type companies continue to trade on healthy metrics. With LNGL holding a material stake in an 8mtpa project at Magnolia, throwing off perhaps US$800-900m of EBITDA per year, the value of the company has plenty of room to increase markedly as and when the project is launched.

Given the uncertainty over tolling fees, it is important to see the effect that varying the tolling fees would have. Given the fixed return demanded by Stonepeak, higher tolling fees will result in an expanded equity position for LNGL. Our analysis indicates that for every US$0.1/mmbtu increase in tolling fee, the value net to investors will increase by c 25% as the effect of the higher equity is magnified.

With A$114m (US$81m) in the bank and no debt at end December 2015, the company is well funded to continue to progress its projects – it believes that the cash reserve can supply the company until 2018. As we discuss in the report, it will likely need some external (equity) finance to help fund the Magnolia project, even with the increased Stonepeak contribution and an increased level of debt funding available (in line with peers at 75%).

The critical junction for investors is the financial close, which will require a number of milestones to be crossed first, not least the signatures of tolling partners in sufficient volumes to make the project commercial.