Last week, Indonesia announced five winning bids in the 2017 oil and gas block tender. The Energy Ministry declared this as a ‘new era’ in Indonesia’s upstream industry. But is it really? Is it a brand new era promising success, or is it a sign of deeper problems in the industry that have still not been solved?
It might be the latter. Take the timeline. The tender was opened in May 2017, and expected to be completed by August 2017. The bidding process was then delayed four times over the year, as the administration grappled with a new model to introduce a gross split production sharing contract mechanism to replace the previous PSC cost recovery standard. But even then, only half of the available blocks were taken. Looking over the list of awardees, there is a striking lack of big names. There is no ExxonMobil, Shell, Chevron or Total… companies that have been instrumental in powering Indonesia’s upstream industry since the 1970s. Premier Oil, KrisEnergy and Mubadala are known players, but aren’t exactly deep-pocketed, while three blocks were taken up by two local players affiliated with PGN, itself in the process of being subsumed into Pertamina.
The remaining five blocks will be re-tendered this year, as part of the Ministry’s ambitious plan to offer some 40 conventional and 3 unconventional oil and gas working areas beginning this month. Some are new, but many have been rolled over from failed auction rounds over 2015, 2016 and 2017. Will this be part of the heralded ‘new era’? From the results of the most recent auction, interest may be lukewarm. Far from attracting new investment, Indonesia has succeeded in pushing long mainstays away – see the recent debacle over the Mahakam block with Total and Inpex. There will certainly be interest. The UAE’s Mubadala Petroleum wants to expand significantly in Indonesia, while PetroChina has also expressed interest in ‘aggressive expansion.’ But these new entrants could run into the same chronic problem many face in Indonesia – the Domestic Market Obligations (DMOs) that mess up the economics of upstream production.
So from one perspective, that five blocks were awarded last month is a success because it comes after a period of severe inertia in creating new E&P opportunities. But from another, it is clear that despite some progress in improving fiscal terms, the big names and the big money is still staying on the sidelines. Still, any improvement may be better than no improvement.
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The shift from coal to natural gas marked a significant change in the energy sources used to generate electricity in the United States in the past decade. This shift was driven primarily by the sustained low natural gas price. In 2020, natural gas prices were the lowest in decades: the nominal price of natural gas delivered to electric generators averaged $2.37 per million British thermal units (Btu). For 2021, EIA forecasts the average nominal price of natural gas for power generation will rise by 41% to an average of $3.35 per million Btu, about where it was in 2017. In contrast, EIA expects nominal coal prices will rise just 6% in 2021.
The large expected rise in natural gas prices is the primary driver in EIA’s forecast that less electricity will be generated from natural gas and more electricity will come from coal-fired power plants in 2021 than in recent years. EIA expects about 36% of total U.S. electricity generation in 2021 will be fueled by natural gas, down from 39% in 2020. The forecast coal-fired generation share in 2021 rises to 22% from 20% last year. However, these forecast generation shares are still different from 2017, when natural gas and coal each fueled 31% of total U.S. electricity generation.
Significant growth in electricity-generating capacity from renewable energy sources in 2021 is also likely to affect the mix of fuels used for power generation. Power developers are scheduled to add 15.4 gigawatts (GW) of new utility-scale solar capacity this year, which would be a record high. An additional 12.2 GW of wind capacity is scheduled to come online in 2021, following 21 GW of wind capacity that was added last year. Much of this new renewable generating capacity will be located in areas that have relied on natural gas as a primary fuel for power generation in recent years, such as in Texas.