How The Netherlands Is Keeping Up With Exploration and Production
Production is declining worldwide and the Netherlands is no exception. This article explainss how the country is responding to the challenge. It forms part of EnergyBoardrooms’ 2015 Netherlands Report – click here to download the whole report.
Like its North Sea neighbors, the Netherlands faces a serious challenge in terms of declining production. An additional USD 1.525 billion is needed to maintain current production levels according to the EBN, the Dutch state-owned body that assists operators. The authorities are keen to turn the tide and ensure 30 bcm per year in production by 2030, especially as much valuable infrastructure will be decommissioned if a sufficient level of E&P activity is not maintained.
Back in 1974, the government already introduced a small field policy to preserve the Groningen asset and encourage production in smaller fields with a guaranteed buyer. Since 1974, smaller fields have actually produced more gas than the larger Groningen field. By 2010, though, production was declining, leading to the introduction of a marginal fields tax that has been welcomed by industry and experts alike. According to Woods Mackenzie, between 2011 and 2028 projects benefiting from this tax will add 17 bcm of reserves or 10 percent, a value of USD 785 million to companies and USD 925 million to the government. “This incen- tive has worked well,” concurs Jo Peters of the Netherlands Oil & Gas Exploration & Production Association (Nogepa). “Now Nogepa hopes to encourage the government to rein- force this allowance which would certainly deliver more developments. The horizon for encouraging investment needs to stretch for the next five to ten years and have an international perspective.”
However, declining reserves and the current low oil price are not the only challenges the industry must face: public opinion of gas has taken a major hit since small earthquakes began to occur around the Groningen field in the late 1980s, with more frequency in the past five years. This summer, the government mandated a cap on production at 30 bcm, a 24 percent year on year reduction. This sharp decrease will have a major impact on overall production, as Groningen field currently represents 75 percent of Dutch production, according to the EIA.
Nonetheless, industry players remain cautiously optimistic. In 2014, of the 93 E&A wells spudded in Europe, the largest number (28) were in the Netherlands, accor- ding to Wood Mackenzie, which also estimates that E&P activity will increase locally in the next five years. “The general consensus seems to be that Dutch upstream is still interesting because of the relatively low capital requirements and low political risk,” argues Eric Wesselman of KPMG. Gilbert van den Brink, managing director of Wintershall, concurs.
“The E&P environment in the Netherlands is good, predictable, and stable. The authorities are reliable partners to work with, despite the maturity.”
As a mature market, “many of the larger players have moved out, to be replaced by smaller operators,” adds Wessleman. “There are more operators here today than in previous years, including some that have entered upstream operations for strategic reasons, including GDF Suez and Taqa. Nonetheless, one important thing to consider is that the overall level of activity in the market today is not increasing, despite the number of new companies arriving,” cautions Jeff Sluijter, partner at EY.
Furthermore, “the current government’s focus on renewa- ble energies means that they are not properly incentivizing the production of gas in the Netherlands… If investment were put into increasing gas power generation, it might in turn make the upstream more attractive,” adds Sluijter.
Operators are thus looking to new plays and novel techniques to increase production. Van Bracht of the TNO argues that “most of the increase in production must come out of existing fields. Enhanced oil recovery is essential, and, along with EBN, TNO is investigating intensively pos- sible means by which to improve recovery rates. The operators have are extremely interested in field life extension and for re-opening stranded fields, and so our work is extremely important to these enterprises.”
German operator Wintershall has not shied away from novel plays in gas, especially for tight gas at the K-18 Golf field. “Developing tight gas offshore is not the most obvious thing to do of course, but we carefully looked at our options, working closely with expert consultants to complement our in-house knowledge from well stimulation to hardware subsea well design. To be totally honest, the development of the field, which is taken as a phased approach, has thus far exceeded our expectations,” van den Brink asserts.
The company is already broadening its portfolio into oil with the discovery of an oil accumulation in block F17 in 2013. “It’s an enviable position to be in, to be in this mature base with an incredible amount of expertise, while still being able to produce a healthy profit margin,” van den Brink concludes. “The recent oil finds will take us into the future. Hence, I still see a bright North Sea future ahead of us.”
The newest entrant to the Dutch market, Petrogas E&P, who purchased Chevron’s North Sea blocks in 2014, is also betting on new plays in gas. “We are now the leading producer of shallow gas in Northwest Europe. It’s still a rela- tively new play, so we see significant running room here in the Netherlands and potentially other areas in the North Sea,” explains Nick Dancer, managing director of Petrogas E&P Netherlands.