The surge in US shale oil has offset declines elsewhere, stabilized world oil supply, prevented gas prices from rising

By Carpe Diem

A frequent question I’ve heard recently goes something like this: With the huge increase in the supply of domestically produced crude oil in recent years – US output is now at a 27-year high and heading for an all-time record high next year – why haven’t gas prices come down? Gas prices today, at a national average of $3.62 per gallon, are more than double the $1.61 per gallon price in early 2009. During that time, domestic crude oil output has increased by 68.5% from 5 million to almost 8.5 million barrels per day (bpd). I provided several answers to the “pain at the pump” question in a recent CD post, and will expand on that explanation here with two revealing charts.

1. The chart below shows monthly US and world crude oil production from January 1994 to December 2013 based on EIA data here for international crude oil production. Despite the 30.5%, and nearly 2 million bpd, increase in US oil output in just the last two years (2012 and 2013), the world crude oil supply has remained flat at about 76 million bpd since December 2011. At the same time, the world economy has continued to grow, with world real GDP increasing 3.9% in 2011 and 3.2% in 2012, according to the IMF, following a 5.2% growth rate in 2010.
2.  The second chart shows monthly world oil production minus US production over the same 1994-2013 time period vs. the same US oil supply. Without US oil output, the world supply of non-US crude oil was on a gradual downward trend between 2011 and 2013. Importantly, If US oil output hadn’t been surging in 2011, 2012 and 2013, the global oil supply would have been declining slightly in those years. Between the January 2011 peak and September 2013, non-US world oil output fell from by more than 2 million bpd (and by 2%) from a record high 70.2 million bpd to 68 million bpd. Oil production outside the US recovered slightly towards the end of last year to 68.8 million bpd, but that’s the same amount of non-US oil produced back in late 2004, more than nine years earlier. As the WSJ reports today, crude oil output since 2005 has been falling outside the US in countries like Mexico (-25%), Iran (-23%), Algeria (-12%) and Libya (-44%).

 

Bottom Line: As can be seen in the top chart, the increases in US shale oil in recent years have offset the output declines elsewhere and thereby prevented the world supply from falling. Thanks to America’s shale revolution, the surging US oil output has helped stabilize world oil supply at about 76 million bpd during all of 2012 and 2013 which has helped stabilize prices at about $100 per barrel. If we had instead experienced a declining world oil supply over the last few years (as seen in the second chart above) interacting with the strong oil demand from the economic growth taking place globally, we would likely be seeing much higher oil prices today and much higher prices at the pump. Even if the rising domestic oil supply hasn’t brought gas prices down, American consumers should nonetheless be thankful for the strong likelihood that without the Great American Energy Boom, they would be paying much higher gas prices today.

 

Related: Fuel Fix is reporting today that:

Geopolitical turbulence in the Middle East would have created a spike in global oil prices if not for the rise of light-crude in the United States and oil sands in Canada, ConocoPhillips CEO Ryan Lance said Tuesday.

As international conflicts have mounted in Libya, Syria and Iran over the past two years, an increase of 1 million barrels per day from U.S. shale and tight-oil production have kept global markets in check, Lance said in a discussion with reporters after the company’s annual shareholder meeting in Houston on Tuesday.

Summary of the New Ministrial Decree no. 12 issued by The Indonesian Ministry of Energy & Mineral Resources on the Purchase of Electricity from Hydro Power Plant by the state electricity co PLN

The summary of the Ministrial Decree (issued on 2 May 2014) is as follows:

1. The Minister authorizes PLN that PLN must buy the electricity from Hydro Power Plant with less than 10 MW (MHPP) through direct purchase and agreed feed in tariff (FIT) which is governed in the Purchasing Power Agreement (PPA)
2. In the PPA, The FIT is stated at:
• The first eight years: Rp 1,075 per kwh x Regional Factor (F); The F is 1x for Java, Bali, & Madura; 1,1xfor Sumatra; 1.2x for Kalimantan & Sulawesi; 1.25x for NTT & NTB; 1.3x for Maluku and North Maluku; 1.6x for Papua and West Papua
•  Year 9 until year 20: Rp 750 per kwh x Regional Factor as similar to above F
• No negotiation & no escalation on FIT in PPA
3. New Player (New MHPP) must start the business via:
• Proposal to the Directorate General for Renewable Energy (DGRE) to be appointed as MHPP company with all requirements ie:
• Company profile
• iPermits from Regional Government (all permits necessary) & Permits from Government (SIPPA & SIKON)
• Pre Feasibility Study which has been technically verified by PLN; PLN must complete the verfication works max 30 days after once all documents related to pre Feasibility Study is well received by PLN.
• Estimated Project Cost/Investment Cost
• Project schedule up to COD
• Statement of availability of land
• Statement of Willingness & Capability to provide 5% of total project cost in the form of certificate deposit to the DGRE within 30 days after the New Player is appointed legally to be the MHPP company
• Statement of Understanding & Willingness & Capability from the New MHPP to develop and operate the power plant which eventually will be announced by PLN
• Statement of Awareness & Responsible to accept and perform sanction which is governed in this Ministrial Decree
• The proposal to the DGRE has a template attached to the Ministrial Decree no. 12
4. The DGRE shall approve or disapprove the MHPP proposal maximum 30 days after once all the requirements within the proposal is well received by the DGRE with cc to the Directorate General Electricity and PLN Board of Directors.
5. The New MHPP shall report the progress of construction of the project every 6 months to DGRE up to COD and cc to Directorate General Electricity and PLN Board of Directors.
6. Up to 30 days after the approval of the DGRE, the New MHPP must submit the certificate of deposit (5% of total project cost) to the DGRE. If not performed then the DGRE shall revoke the approval and 2 years sanction to the New MHPP not being able to resubmit a similar proposal.
7. The New MHPP, after submitting the certificate deposit, must apply for “temporary permit for producing electricity” (Temporary IUPTL).
8. Once the New MHPP receives the permit of Temporary IUPTL then the New MHPP must submit the copy of the approval of permit to the DGRE.
9. Within 90 days after the issuance of permit of Temporary IUPTL then the New MHPP must submit the Feasibility Study (not the pre-FS) and other required documents to PLN for the signing of PPA. PLN is then obliged to sign the PPA (cc to the DGRE) within 30 days after all documents are well received by PLN.
10.  PLN shall publish the model of PPA (60 days after the issuance of this Ministrial Decree or 1 July 2014).
11. If PPA is not signed within that 30 days period, then the New MHPP approval from the DGRE shall be terminated, 2 years sanction to the New MHPP not being able to resubmit a similar proposal, and 25% penalty off the certificate deposits.
12. PLN must state in the PPA the limitation of financial closing of 15 months after the signing of PPA. If the financial closing is not fulfilled, then the New MHPP approval from the DGRE shall be terminated, 2 years sanction to the New MHPP not being able to resubmit a similar proposal, and 50% penalty off the certificate deposits.
13. Once the New MHPP has reached the financial closing then the New MHPP must apply for the Permanent IUPTL;
14. Within 3 days after the issuance of the Permanent IUPTL, the New MHPP must convey:
• the copy of the Permanent IUPTL,
• prove of financial closing, and
• the plan to use the fund in the project to the DGRE. Certificate deposits then can be released to finance the project.
15. Up to maximum 3 months after the issuance of the Permanent IUPTL, the New MHPP must start the project.
16. If the New MHPP fail to start the project then PLN must revise the first 8 year FIT with certain penalties (unless caused by force majores governed in the PPA) such as:
    
    • 3 months delay – 1% penalty to FIT
    • More than 3 up to 6 months delay – 2% penalty to FIT
    • More than 6 months delay – 3% penalty to FIT
    • 15 months delay and more then approval from the DGRE shall be terminated, 2 years sanction to the New MHPP not being able to resubmit a similar proposal, and 100% penalty off the certificate deposits (if not yet used)
17. Those MHPP, which are now in operation under the Ministrial Decree no. 4 2012, shall not be benefitted to the new revised FIT
18. Those MHPP under the Ministrial Decree no. 4 2012, which already have PPA and are not in the commissioning stage, can negotiate the FIT with the PLN with a maximum adjusted FIT not more than Rp 880 per Kwh x F. The negotation must be approved by the DGRE, and the Minister of Energy & Natural Resources on the final stage must approve the final negotiated price. Sanctions are also applied to those MHPP when the negotiated price has been approved by the Minister and the projects are not carried through

My comment:

When reviewing the MD-12, I was full of excitement because the clarity and fairness of the decree was seen througout every article. The Government of Indonesia (GOI) via the Ministry when the decree was written must be clouded by the good spirit and enthusiasm to promote the business of hydro power plant particularly the MHPP to be prosperous and supportive to the need of the country's electricity demand.

As an Indonesian, I strongly believe that the mission of the GOI to decide the FIT for MHPP quoted in Rupiah (different than any other large power plant producers who receive US Dollar revenue) is to balance or somewhat reduce the risk of the state owned electricity company PLN on its foreign exchange exposure risk. I could say that the MHPP players have not only supported the country to electrify the nation (like any other power players), but also appreciated the problem that PLN is currently facing. This is one thing the GOI must understand and should incentify the players in MHPP. It would be great if in the MD-12, the Ministry could have thought the importance of price escalation. Escalation serves two main purpose which are to combat inflation and to give MHPP players maintaining the facility well.

The GOI realizes that the old tariff (Rp 656 per kwh) was no longer attractive, then the GOI should incentify the existing operating MHPP players so that they can reinvest the benefit for new projects. The GOI must also remember that these running MHPP developers have sweet and sour experiences in building the facility; Thus, in their next projects, that past learning curve shall support them. It would have been rewarding if the MD-12 took that concerns into account.

The last article no. 18 was a mind blowing, and out of fairness, I could say that this chapter has ruined the good spirit of the MD-12. The chapter incentifies those MHPP players, who have the PPA and are not yet in operation. These players, the chapter said, can negotiate the FIT to a certain level (maximum Rp 880 x F per kwh) which would be considered acceptable by PLN and approved by the Minister. It is very good, so that these players can right away step up its investment activities. However, the chapter discriminates the existing players who are already in operation. They can not get the benefit out of this MD-12. The GOI forgot that the existing running MHPP is now suffering with higher interest rates from the bank loans and rising costs from maintenance. Escalation clause is important especially to combat the inflation because inflation kills this business, and the negotiated FIT for MHPP article should be open for everyone, new comers or existing players.

Overall it is a step forward, and I just hope that the GOI and the community of MHPP have the similar spirit and energy for the betterment of this business to electrify the nation.

What's acceptable Project IRR for Mini Hydro in Java, Indonesia? Does it matter? or Any other things to be considered?

This question has challenged many mini hydro players in Indonesia.  With the existing feed-in-tariff (FIT) of Rp 656 per kwh (assigned by the Ministry of Energy and Mineral Resources Decree back in December 2009) for Java Island as a benchmark tariff, today is valued at only USD 5.5 cents per kwh which represents a fall by 18% since August of 2013.  At the same time, we can effectively see that all construction costs has risen by 20% in Rupiah terms.  Not to mention, the country's inflation which was 8% in 2013.

Allow us to set an example on mini hydro investment in Java Island, Indonesia.  According to our real case experience, the investment for mini hydro in Java in general is estimated to be USD 1.5 - USD 1.8 million per MW.  Of which, civil works (including transmission, project management, engineering cost, and IDC) account for USD 0.9 to USD 1.0 million per MW, and the rest is allocated for land and M&E for USD 0.6 - 0.8 million per MW.  Assuming the project is 70% financed by bank loan with capacity plant factor of 65%, the project will generate an IRR of 12 - 15% in today's interest rate of 12.0% p.a and 10 years payback period (including 2 years construction period).

In summary, we can argue that the project IRR of 12 - 15% is too low or just right. Many would say that it is just not very attractive since the rate is equal to the bank's yield. Whatever the IRR level might be, we can't escape from the 10 years payback period with 15 years power purchase agreement.  The key is to find the banks or financial institutions who are willing to support us for the next 10 years.  It is a long term partnership.  It is a perpetual game and a fixed income play.

The writer hopes that with the right structure and economical yield, the domestic infrastructure financing institutions like Sarana Multi Infrastruktur, Indonesia Infrastructure Fund, Pusat Investasi Pemerintah, syariah banks, and other large commercial banks in Indonesia can contribute more in boosting the investment of mini hydro power plant.  They have done so, but the interest rate is just too high momentarily. Increase in new FIT and breakthrough design of FIT that the writer proposes in his other previous writings may reenergize this lucrative investment.

Why Increase in Feed-in Tariff for Mini Hydro Power Plant in Indonesia Is Not the Only Factor Urgently Needed...New Feed-In Tariff Payment Mechanism Needs to be Changed ! -

By The Flying Garuda

Indonesia's good economic climate during 2009 until the 1st half of 2013, in addition to the Decree of Minister of Energy and Mineral Resources (MEMR) in late 2009 on the revitalization of renewable energy, had surely supported the growing interests in the investment of renewable energy sector, particularly in mini hydro power projects. More investors started to test the water in the sector.

Investing in this sector takes more than money & passion. It takes so much patient & energy. The work starts from processing the permit from the regency, detailed river & land survey, hydrology study, & soil test. These steps may take easily two months, & when the results are considered worthwhile, one can further continue making pre-feasibility study & land acquisition program. Not forgetting additional permits like the regency location permit, environmental approval, water usage, & project construction license. These steps are still not enough. Prospective investors have to start talking to the state-owned electricity company PLN whom by law will and must purchase the power from the project. Acceptable detailed engineering design & the complete feasibility study must be submitted & reviewed by PLN. In parallel, investors also have to apply for the permit to produce power from the MEMR. The whole process easily takes one year to complete until investors obtain the Purchasing Power Agreement with PLN.

The other challenge is to source secured financing from banks. Not many banks in Indonesia understand the business of mini hydro power plants. Some simply don't understand the business, but many have the views that the project is quite risky. Number of reasons why banks view this project is risky. For example, considered as a greenfield project, 60% of the mini hydro power total project cost is allocated for civil work, & the rest consists of mechanical, electrical, & balance of plants. Bear in mind many of potential mini hydro projects are located in remote areas. This factor weakens the collateral value of the bank loan in the case when the bank needs to reposses the collateral in the area which has minimal land value with unfinished assets. The project's nature of fixed local currency tariff with long-term tenor of more than 10 years has both forex risk and risk of inflation of operating costs, of which the value of Rupiah tariff will no longer keep up with the increasing costs.

The obstacle doesn't stop here. The M&E on turbines and generators are priced in US Dollar & the recent Rupiah depreciation in the 2nd half of 2013 had a significant impact to mini hydro power plant projects. Bear in mind that the Purchasing Power Agreement with PLN is in Rupiah locked up with no adjustment for 15 to 20 years. Unfortunately, the depreciation of Rupiah has also pushed the rise in cost of basic raw materials for civil works like cement, steel pipes, iron bars, & equipment rentals.

High pre-operating costs, long process of approvals, increased construction civil works costs and weakening Rupiah currency surely caused the fall of the project's attractive yield to the level that may no longer be suitable or acceptable for investors. This dilemma should trigger the creativity and innovation by the PLN and the Country's Ministry of Mines and Mineral Resources to do the followings:

1. New Design on Tariffs: The Ministry should divide the tariffs into two composition i.e. the Rupiah and USD portion. The total feed-in tariff should be priced proportianately in a composition of 60% in Rupiah tariff and 40% in US Dollar tariff. For example, if the government decides to improve the basic feed in tariff from Rp 656/kwh to Rp 800/kwh in Java, then the new designed feed-in tariff in Java should be 60% of the energy produced by the mini hydro power plant is priced in Rupiah i.e. Rp 800 per kwh, and 40% of the energy produced is priced in USD at USD 0.067 per kwh (Rp 800 divided by the prevailing Rp exchange rate to USD of Rp 12,000 per kwh). Thus, the energy produced from the power plant is 60% paid in Rupiah and 40% paid in USD which is converted to Rupiah when paid by PLN. By doing so, the government has created the natural hedge on foreign exchange for the project.
2. Inflationary Adjustment Factor to Tariff: It would also be fair if the basic feed in tariif can be adjusted yearly on the Rupiah portion based on the official inflation rate announced by the government. Using our example, the 60% Rupiah portion of Rp 800 per kwh is automatically adjusted by the rate of inflation yearly. This would minimize the inflation risk on a long term commitment to PLN for the next 15 years. As a result, steady fair profit generated from the power plant can be used for maintenance assuring the delivery of energy to the PLN.

Conclusion: It is just not a matter of tariff increase. The government must look beyond this tariff issue. More practical check list of approval system by the related government offices to speed up the process and investor friendly and simple tariff automatic adjustment with fair and healthy proportianately design payment mechanism can be introduced. Afterall, the electricity tariff charged to the end customers are adjusted yearly. It is then fair to adjust the feed-in tariff of power producer on yearly basis. It is the government initiative and the country's mission to prosper the renewable energy business. Let's make the flow of energy from water to power easier and more productive and beneficial to the stakeholders.