Neptune Cuts Output Guidance, Spends on Growth

Privately-backed UK producer Neptune Energy reported a dip in production in the third quarter to 131,000 barrels of oil equivalent/day, almost exactly half of which was gas. Problems affecting Gudrun and Gjoa in Norway, Cygnus in the UK, outages in the Netherlands and the delayed start-up for the Algerian Touat gas field were the main reasons.

LNG sales from Indonesia were down, owing to lower nominations from Asia, leaving more LNG in the Bontang terminal. Neptune had sold about a quarter less LNG in Q1-3 from there than in the same period last year, with most of that drop being in the third quarter. "While we believe this is a short-term issue, we anticipate a risk of some curtailment in 2020 and have protection through take-or-pay provisionsin our gas sales agreement," it said.

It has lowered its full-year guidance as a result, but it expects a return to normal this quarter. And the company has big projects ahead of it that will add about 110,000 barrels of oil equivalent by the end of 2021, and a rise in expenditure to $1bn-$1.1bn which will push up its debt gearing.

It reported a pre-tax profit for Q1-3 of $445.2mn, down from $675.3mn last year and net income of $83.2mn, down from $152.5mn.

Among the highlights were an “important discovery” at Echino South, which could be fast-tracked as it is near existing infrastructure offshore Norway, with an estimated 38-100mn barrels of oil equivalent recoverable resources. And acquisitions in Indonesia will provide access to long life, low-cost reserves and resources in addition to exposure to multi-trillion ft³ exploration potential across the basin.

Neptune expects robust full year cash flow of over $1bn, despite modest commodity prices and lower production. This reflects "disciplined capital allocation and a low cost base of around $10.5/boe."

It said it made “significant strategic progress in the third quarter,” and its acquisition of Edison E&P’s North Sea assets from Energean Oil & Gas, boosting output with effect from February, was “an excellent fit with our existing portfolio in Norway and the UK.” Nova and Dvalin are expected to add 12,000 boe/d over the next two years and the very large Glengorm gas and condensate find in the Central UK (Neptune: 25%) adds significant upside potential for the longer term.

It said it is committed to a production profile that is weighted more towards gas than oil "due to its vital role in the transition to a lower carbon energy mix and stronger demand growth fundamentals. We have one of the lowest CO2 emissions intensities in the sector, and are implementing a new environmental policy, which details our commitment to reduce emissions, improve energy efficiency and achieve a long-term intensity measure."

While operating costs for the third quarter were $11.2/boe, reflecting lower production in the quarter, it expects them to be within the original guidance range for the full year. Cost efficiency programmes remain on track across the group, with roles already taken out in the Netherlands and Germany and work progressing on closing the Paris office, another legacy from Engie.

During the third quarter, its average realised commodity prices, excluding the impact of hedging, were $64.2/boe for oil and $3.6/’000 ft³ for gas, reflecting lower commodity prices during the period. It has hedges in place for 49% of crude oil sales and 65% of dry gas for the remainder of 2019.

Lower production and weaker commodity prices resulted in operating cash flow of $334.2mn. However, it was still able to invest $278.7mn in the third quarter, largely in Norway at the Njord and Fenja projects.

In October, it said it would split the global operations role into two, to focus more sharply on Europe and North Africa/Asia Pacific. Neptune’s UK business, boss Pete Jones has been appointed VP of Operations for Europe, while Philip Lafeber joins the executive management team in his current role as VP of Operations for North Africa and Asia Pacific.