Sponsor completion guarantees in LNG construction financing: Part II

As the world of North American LNG financings continue to evolve, OGInsights explores the use of completion guarantees in construction financings.

In Part II of this two part series, we look at the conditions precedent to project completion which typically need to be satisfied for release of the completion guarantee by lenders.

Construction criteria requires "substantial completion" under the EPC Contract. In addition, operational tests must be satisfactory and includes production of on-specification LNG for a continuous 90-day period.

At completion, maximum stated debt to equity ratio is not to be exceeded - should the ratio be too high, project sponsors are required inject capital to bring the ratio within covenanted levels. Operating account and Debt Service Reserve Accounts are also to be funded to required levels.

From a legal perspective, project agreements and finance documents must be in full force and all governmental authorisations need to be in place, together with certification of environmental and social compliance in line with covenant requirements.

Financing structures continue to evolve to support LNG projects with lenders and sponsors driving the innovation to (i) enable projects and (ii) improve project economics whilst managing the risk that lenders are exposed to.

In Part I, OGInsights covered the use of and reasons for project completion guarantees from a sponsor perspective.

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Sponsor completion guarantees in LNG construction financing: Part I

As the world of North American LNG financings continue to evolve, OGInsights explores the use of completion guarantees in construction financings.

At a high level, the project sponsor guarantees debt service under a guarantee until the construction is complete. To the extent that a project does not reach completion (normally by a certain long-stop date), then the sponsor will be obliged to repay all of the debt under the guarantee.

The provision of a guarantee comes with a number of benefits:

1. Lenders are more likely to agree to the equity funding of a project to be back-ended (i.e. construction costs are first funded by debt before equity rather than pro rata). This improves project economics (NPV and IRR).
2. Lenders will allow use of pre-project completion cash flows as a source of “equity” funding towards the project, thus replacing “hard” equity contributions. In the absence of a guarantee, lenders typically do not give credit to such uncontracted cash flow and such cash generated is trapped until project completion is achieved (as normally insisted upon by lenders). When a guarantee is in place, lenders are more or less agnostic to whether pre-completion LNG sales are contracted or spot sales and can give credit to such cash flows.
3. Lower pre-completion debt costs – reduced commitment fees and margins, reflecting that of the sponsor corporate credit strength (with normal adjustments for pricing and tenor). Pricing could be c.15-30bps cheaper under a construction guarantee structure fr example

One possible downside is that higher amounts of debt are drawn in the early years of construction (vs. when no guarantee is in place) if equity funding is back-ended, and hence interest costs could be higher, although this is partly offset by the lower debt pricing mentioned above.

Note that in a financing without a completion guarantee, lenders require hedging at financial close of the facility with a substantial amount (typically >60%) under either fixed interest rate or hedged throughout the construction and operations period. A construction guarantee provides more flexibility with regard to hedging during the pre-completion/construction period as the interest rate risk is borne by the sponsor; at project completion, lenders will require fixed rate/hedging in place concurrent with the release of the guarantee.

Financing structures continue to evolve to support LNG projects with lenders and sponsors driving the innovation to (i) enable projects and (ii) improve project economics whilst managing the risk that lenders are exposed to.

In Part II, OGInsights explores the conditions that constitute project completion.

#US #LNG #financing

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Valuera nears TDs at Inanli-1

Valeura has reached 4,145m on the Inanli-1 well (TD 5,000m, c.800m deeper than Yamalik-1).

It has encountered over-pressured gas with a c.40% net-to-gross, similar to that of Yamalik-1, with gas flows - all pointing to promising results. In addition, the well has encountered more naturally fractured rock than encountered in Yamalik-1 with increased gas levels recorded at the fractured intervals.

Drilling is continuing to 5,000m with an extensive set of logging and well tests planned. Operations are expected to be completed in January with fracking and flow testing expected to commence around the end of Q1/19. Inanli-1 is the final well to be funded by Equinor.

Devepinar-1 appraisal well is the next scheduled to be drilled following completion of Inanli-1.

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Petronas enables Cheniere Sabine Pass Train 6

Petronas has agreed to enter into a 1.1mtpa offtake deal with Cheniere on Sabine Pass Train 6 which should enable the train take FID shortly. With a foundation buyer now in place, Cheniere can continue with raising finance to progress the 4.5mtpa project.

Under the deal, Petronas has signed up to 1.1mtpa on a FOB basis for 20 years. As common with east coast LNG contracts, the pricing will be indexed to the monthly Henry Hub price, plus a toll for the liquefaction services plus margin.

Petronas vice president of LNG Marketing & Trading, Ahmad Adly Alias said: "Petronas is pleased to enter into this long-term relationship with Cheniere... With the addition of this new volume, it will enhance Petronas' supply portfolio and further strengthen our position as a reliable global LNG portfolio player."

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SNE partners progress to FEED for Phase 1 of the development

The SNE JV offshore Senegal (Cairn 40%, Woodside 35%, FAR 15%, Petrosen 10%) has entered FEED for Phase 1 of the SNE development. The engineering contract has been awarded to the Subsea Integration Alliance (OneSubsea, Schlumberger and Subsea 7).

First oil is being targeted for 2022 with an initial production rate of c.100mbopd. The exploitation plan had previously identified a total development of 500mmbbl of oil over a multi-phase development with the Phase 1 FEED targeting 230mmbbl from the base, thicker sand package.

Woodside noted that the Senegalese Minister of Petroleum and Energies has approved Woodside’s transition to operator of the RSSD JV (Rufisque, Sangomar and Sangomar Deep) and the SNE development. Separately, FAR continues its commercial arbitration around the initial deal between Conoco and Woodside.

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DEA acquires Sierra Oil & Gas

DEA has expanded its international footprint into the Americas by acquiring Sierra Oil & Gas from Riverstone Energy.

The Sierra portfolio includes the prized Zama discovery (Sierra Oil & Gas 40%, Talos Energy 35%, Premier Oil 25%) and an extensive exploration acreage position offshore Mexico.

The value of the deal is reported  at ~USD500 million which provides a positive read-through for Zama of over USD300 million net to Premier.

The acquisition further bolsters the Wintershall DEA portfolio ahead of its planned IPO in 2019-2020 and adds prospective acreage in what is otherwise a production (but stable) weighted profile.

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Brasse's growth halts as Faroe's Rungne well disappoints

Faroe announced in November that the Rungne well came in disappointing with only sub-commercial levels of gas found. Although encountering hydrocarbons, the estimated volumes of 12-57bcf gas and 0.5-3.9mmboe condensates will mean the discovery is non-commercial on a standalone basis. Nevertheless it could form a future tie-back to Brage or Oseberg.

Faroe's exploration programme continues with Brasse East which could be another chance for Faroe to grow the Brasse Area prior to taking FID. Faroe is currently going through concept selection for the field with two potential hosts: Brage or Oseberg.

Related posts:

• Brasse - Brage's younger sibling
• Brasse continues to grow
• Brasse flow test shows promising results

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ExxonMobil makes 10th oil discovery offshore Guyana; resource increased to 5+ bnboe

ExxonMobil announced its tenth discovery offshore Guyana and its sixth discovery on the Stabroek Block in the past year.

The Pluma-1 well encountered c.121 feet of high-quality, oil-bearing sandstone reservoir and is located c.17 miles southwest of the Turbot-1 well and follows previous discoveries on the Stabroek Block at Liza, Liza Deep, Payara, Snoek, Turbot, Ranger, Pacora, Longtail and Hammerhead. The discovery adds to ExxonMobil's previous 4+ bnboe resource estimate which is now being increased to 5+ bnboe.

The drillship will next drill the Tilapia-1 prospect located 3.4 miles (5.5 kilometers) west of the Longtail-1 well, with ongoing work to evaluate development options in the southeastern portion of the block and potentially combining Pluma with the prior Turbot and Longtail discoveries.

Phase 1 of the development is underway, and will include 17 wells connected to a FPSO with 120mbopd capacity by early-2020.

Phase 2 is due to be sanctioned in early-2019 and will use a 220mbopd FPSO.

For Phase 3, ExxonMobil plans to use an 180mbopd FPSO, with first oil in 2023. FID for Phase 3 is expected in 2019, which is now further supported by the Pluma discovery.

ExxonMobil sees the potential for five FPSOs producing 750mbopd by 2025 offshore Guyana.

#ExxonMobil #Guyana #Pluma #Liza #Stabroek

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