Header
 

August 25, 2015
Massachusetts AG Probing Impact of Gas Pipeline Expansion Plans

Massachusetts's Attorney General Maura Healey has commissioned an independent study to examine the actual need for natural gas capacity for electric generation to meet the power needs of Massachusetts residents, according to the Massachusetts Energy Marketers Association (MEMA).

Healey is on record citing her concerns relative to the need for natural gas pipeline expansion, specifically the Kinder Morgan Tennessee Natural Gas Pipeline and the Spectra Energy Access Northeast Natural Gas Pipeline, both of which are proposed for construction using taxpayer/ratepayer dollars, not private investment funds, MEMA said.

Michael Ferrante, president of MEMA, told OPIS that the pending AG report could change the course of these rapid natural gas pipeline expansion plans in New England.

"The Governor (Charlie Baker) and his top staff have also told us that they will wait to see the AG's report," he said.

OPIS notes that the Northeast states have seen a steady trend of natural gas conversion from heating oil, creating a heavy reliance on gas amid limited retail supply. In the past winter, the Northeast region saw consistent gas supply rationings in response to peak demand caused by subzero temperatures. Utilities, residential homes and commercial buildings are forced to turn to heating oil as a backup fuel.

While U.S. natural gas supply remains in abundance, the logistics part of the supply chain continues to play catch-up to the rising demand. In the Northeast, several gas and logistics companies, including Kinder Morgan, TransCanada, Berkshire Gas, Columbia Gas, Connecticut Natural Gas Corp., Liberty Utilities, Constitution Pipeline Co. and TGP, are racing to build new gas pipelines over the next few years.

Also, in July, Connecticut Energy Marketers Association (CEMA) lost its lawsuit against the state's natural gas expansion and conversion plan, but it plans to appeal against the court decision.

The Hartford Superior Court in Connecticut has ruled in favor of the Department of Energy and Environmental Protection's (DEEP) motion to dismiss CEMA's case concerning the natural gas expansion and conversion plan.

MEMA said that under a grant from the Barr Foundation, the Attorney General had commissioned a report to be done by Boston-based The Analysis Group. The report will also examine the current energy infrastructure to ascertain if there are better ways to plan for meeting the fuel needs of power generators, such as general supply DNS commodity hedging for fuel such as heating oil and LNG.

Healey's office is also expressing concerns that the building of these natural gas pipelines to dead-end in Maine will simply provide an outlet for these pipeline companies to export natural gas into the world market, MEMA said.

If that is ultimately part of the business plan, the taxpayer/ratepayer dollars should not be funding these ventures, it said.

The New England Fuel Institute (NEFI) and MEMA provided the Attorney General's office with numerous documents to help support their position that the regional infrastructure needs are already in place to support the electric power generators' fuel requirements.

NEFI and MEMA also shared information relative to biodiesel blended heating oil and the greenhouse gas savings that could be realized using such fuels, compared to natural gas.

Both organizations will continue to be active with the Attorney General's office on this issue and will keep members informed of any new developments.

Besides the AG report, GDF Suez Energy North America began to send copies of a new report to policy makers in Massachusetts last week, highlighting plans to charge electric ratepayers for more pipelines would hurt consumers, according to local media reports.

GDF Suez owns and operates the LNG import terminal in Everett. It is noted that a higher gas pipeline delivery could hurt LNG import economics at Everett terminal. The new report was a study commissioned by GDF Suez to examine energy market dynamics in New England and the impact of public funding from electric ratepayers to build gas pipelines.


August 19, 2015
Panama Power Plant: Propane ... or Ethane?

OPIS's first look at the renowned Panama tender for a gas-fired power plant (July 23) came down squarely on the side of propane as the most economic fuel choice and the probable winner in the sweepstakes among competing fuels to fire the turbine-generators.

The battle for the Panama tender, to be decided on Monday, Aug. 31 according to the latest indications from government agencies, has now morphed into a battle royale between fuels competing to establish themselves as the cheapest long-term option for baseload power generation in the Central American-Caribbean (CAC)region.

The conclusion from the July 23 article was that LNG had already lost the battle to propane. A previous tender was awarded in 2013 for a 670-MW gas-fired plant mated with an LNG regas terminal side-by-side. The gargantuan scale of the project, for a tiny country with 3.6 million population, was exceeded only by its cost, which we estimated at $1 billion. Kibitzers subsequently informed us that the real cost was closer to $1.4 billion.

As related in the earlier article, when the new government of Juan Carlos Varela replaced that of Ricardo Martinelli in July 2014, they killed the LNG plan and put together a tender for a smaller facility in the 350-400-MW range. That is the tender that will soon be decided.

But tossing aside LNG as a viable fuel choice was premature, as we quickly learned by delving into the big project in El Salvador (OPIS, July 30). Their power plant is more prudently sized, 355 MW, and is being mated with a small regas terminal for 500,000 tons per annum (500 KTA) to supply 63 MMcfd to the engines. The plant is due to go into service in 2018.

As the Panama horse race comes into the final turn, it is turning into the most successful tender ever put forth in the CAC region. The frequent complaint is that severe bidding restrictions narrow the potential field of bidders down to where there is often only one bidder. In contrast, this tender, by the latest count, has at least seven bidders with proposed projects before the Autoridad Nacional de Servicios Publicos (ASEP), Panama's utility regulator. All have received "provisional licenses."

For our purposes, the only projects that matter are those proposing to run on some form of gas energy. Considering the fate of the last LNG plant proposal, we were surprised to see two LNG proposals crop up on ASEP's latest list. One proposed by Caribe NG Power, the 300-MW Gatun generating station, is sited at Cristobal, at the Atlantic entrance to the Canal. This one looks like a downsized version of the 670-MW plant killed last year.

The other is the 366-MW Termogas plant proposed by Grupo Energetico del Caribe. It is unclear from the ASEP list what plans these operators have to manage their gas supply, but it would seem inescapable that the power plant would need to be paired with a regas terminal. The El Salvador project suggests that the price tag for the combination is $900 million.

The big news since our Propane Turbine story is a proposal duly submitted to ASEP in July, and in receipt of a provisional license, for a 400-MW plant to run on ethane as its fuel. What makes this submission even more intriguing is the plan to power the generators with reciprocating engines provided by Wartsila. Taking a leaf from El Salvador's playbook, an innovative gas-fired plant will be built around old, reliable recips instead of gas turbines.

The ethane power plant proposal was put forward by Gator Partners and is named Energia Corotu. The proposal completely shakes up the scenario developed in the OPIS July 23 story. There, the prime movers were to be turbines, the fuel of choice was propane, and the location was moved from the Atlantic side of the Canal (Colon) to the Pacific side (Panama City) where there is high demand growth for electric power.

Scrap all that about moving the generating capacity to the Pacific side. Colon, the city of about 100,000 population on the Atlantic side, is the site of all the pending power projects in the queue to be considered for the Aug. 31 tender.

When considered as a geographical reference point, Colon has two sides. The front is the world port of Cristobal that faces the Atlantic entrance to the Canal. The back is in the marshes east of the city centered around the old Refineria Panama on a peninsula referred to as Bahia Las Minas. To get the lay of the land, Google Map users will get the most help by entering Puerto Pilon, Colon in the Map window.

In the roster of current project proposals, four are in front, sited in Cristobal or on Telfers Island just south of it. Of these, the most important is the 300-MW Gatun gas-fired plant, likely sited on the same plot as the canceled 670-MW LNG plant and regas terminal.

But the serious action is in back, where the bulk of Panama's existing thermal generating capacity of 1,150 MW is already located. The list is headed by the 280-MW Bahia Las Minas station owned by Engie (the renamed GDF Suez). The top four thermal facilities on the back side constitute 616 MW between them, 54% of the national thermal total.

No less than eight of the proposals in the current project queue are sited on the back side, three in Puerto Pilon, four in Cativa just to the west, and one in Sabanitas just to the south. The ones that matter here are both in Puerto Pilon: the 400-MW ethane-fired plant of Gator Partners, and the 366-MW Termogas gas-fired facility, presumably with LNG regas capability.

In the context of the main tender being run by ASEP, our sources predict that only one of the large facilities, 300 MW and up, now on the drawing board will come to fruition. By this calculus, the game is between one of the two LNG proposals, Gator's ethane-fired plant, and the 350-MW propane-fired plant described in the July 23 article but not showing in the ASEP list of projects with provisional licenses.

The liabilities of the LNG solution are already well-known. The regas terminal virtually doubles the capex required for the generating plant. The El Salvador budget of $900 million offers a handy benchmark for what a comparably-sized power plant and regas terminal would cost.

In this size range, 300-400 MW, the size appropriate for the CAC region, the advantages of a power plant fired by propane or ethane are compelling. Even at the OLD prices of ethane or propane, knocking 40% off the capital cost of the power plant would almost certainly make the discounted cash flow (DCF) for those plants well above what would be shown for the gas-LNG option.

But now, with ethane extraction economics destroyed, and ethane showing a negative netback at the gas plant, the utility buyer gets his ethane at fuel value, i.e., the equivalent of gas originating at Henry Hub.

And propane economics, for the gas processor, are little better. At last week's Mont Belvieu average price of 37.3ct/gal for propane ($15.21/bbl), against an average oil price of $43.21 for WTI, the propane-oil price ratio (POPR) stood at 36%, in contrast to an historical average over 70%. The gross propane frac spread was $1.26 per MMBtu (11.5cts/gal), which does not cover the logistic costs of getting the product to Mont Belvieu and getting it fractionated.

Granted, propane will not stay at this severely depressed level forever, and we would surmise that the POPR will recover to somewhere in the 40s during the fall and winter demand season. But at that level, the economics of a propane-fired power plant still runs rings around the LNG option. On a fuel-cost basis alone,Belvieu propane landed at Colon probably beats laid-in cost for LNG. When the capex difference is factored in, there is simply no contest.

All this brings us, finally, to the ethane-fired option. The preliminary price tag Gator Partners has put on its proposal is a super-cheap $400 million, $1 million per megawatt. We will surmise that they have not factored in the logistics costs of a fully refrigerated ethane terminal to receive the newly built ethane gas carriers now in development at the world's shipyards. So let's add on, say, $200 million for the fully-ref tanks and the dock to receive the ethane carriers.

Just in terms of raw project costs, we're looking at $900 million for the LNG option, maybe $600 million for the ethane option, maybe $500 million for the propane option. Again, for a propane-fired plant at Puerto Pilon, we need to factor in the costs of a propane terminal adjoining the power plant, but capex on that would be much lower than for the ethane terminal.

Can the Wartsila recip engines running on ethane do the job? A project finance consultant says those big recips, properly tuned, can run on anything, and they're way less temperamental than turbines. They may not run at quite as high an efficiency factor as the LM-6000 turbines discussed in the July 23 article. But the steady, trouble-free operation can probably make up for any deficiency in pure operating efficiency.

What about the economics of ethane imported from Mont Belvieu? The finance expert asks how they could get any better. Ethane is being extracted as a loss leader at gas plants from coast-to-coast. Hopefully propane will soon lift its head above breakeven extraction value to justify operating the gas plants. But North American ethane's long-term value (for the next 15 years) is likely to stay at or below extraction economics. Delivered at Puerto Pilon, it will be cheaper than the cost of gas from LNG delivered to the site.


August 19, 2015
Market Yawns at Propane/Propylene Stock Build, Mulls 100 Million Bbl Total

Will total U.S. propane/propylene stocks exceed 100 million bbl this year? That's the question that surfaced in the wake of this morning's news that total U.S. propane/propylene stocks rose 1.1 million bbl to 93.9 million bbl in the week ending Aug. 14, according to the Department of Energy.

On average, stocks were called to build 1.5 million bbl, according to an OPIS market survey. Today's build, while on the low side, was in line with market expectations. And as a result, traders turned their eye toward the 100-million-bbl question.

The answer uncovered in OPIS's unscientific market poll: the odds are favorable.

"I think we will be in the 99 to 101 (million bbl) range," said one trader. "That's not a flashy call, but we will see steady builds to get to that range."

The Oct. 1 start of the winter heating season is less than six weeks away. If the U.S. sees a build on the order of 1 million bbl or more each week, that should push the total over 100 million bbl.

"I think it is probably gonna come down to a rounding issue," noted one source. "I'd think 100 million makes sense."

Any kind of disruption to exports, such as a storm, would likely push inventories over 100 million bbl, pointed out a third source. September is a month that frequently sees Atlantic hurricane births, but this has been a quiet year, so far.

Over the past three weeks, propane/propylene stocks built on average 1.47 million bbl. Over that time, traders note that market fundamentals have been steady and uneventful.

NGL production remains strong from gas plants as well as from refineries. Weekly Natural Gas Plant Liquids estimated production, which includes propane/propylene, was unchanged for the week at 3.249 million b/d. But, it was up 369,000 b/d over the same period a year prior. The four-week moving average, at 3.281 million b/d, was up 13.5% over the same period a year prior.

Refinery production ticked down for the week to 1.62 million b/d from 1.651 million b/d. But looking at the four-week average, refinery propane/propylene production, averaging 1.64 million b/d, is about 100,000 bbl over year-ago levels.

Looking at products supplied, data shows that the implied demand for NGLs is not keeping pace with production. For the week, average estimated demand stood at 1.01 million b/d, up 152,000 b/d. The four-week average stood at 945,000 b/d, only up 2.9% from year prior.


August 19, 2015
Panama Power Plant: Propane ... or Ethane?

OPIS's first look at the renowned Panama tender for a gas-fired power plant (July 23) came down squarely on the side of propane as the most economic fuel choice and the probable winner in the sweepstakes among competing fuels to fire the turbine-generators.

The battle for the Panama tender, to be decided on Monday, Aug. 31 according to the latest indications from government agencies, has now morphed into a battle royale between fuels competing to establish themselves as the cheapest long-term option for baseload power generation in the Central American-Caribbean (CAC)region.

The conclusion from the July 23 article was that LNG had already lost the battle to propane. A previous tender was awarded in 2013 for a 670-MW gas-fired plant mated with an LNG regas terminal side-by-side. The gargantuan scale of the project, for a tiny country with 3.6 million population, was exceeded only by its cost, which we estimated at $1 billion. Kibitzers subsequently informed us that the real cost was closer to $1.4 billion.

As related in the earlier article, when the new government of Juan Carlos Varela replaced that of Ricardo Martinelli in July 2014, they killed the LNG plan and put together a tender for a smaller facility in the 350-400-MW range. That is the tender that will soon be decided.

But tossing aside LNG as a viable fuel choice was premature, as we quickly learned by delving into the big project in El Salvador (OPIS, July 30). Their power plant is more prudently sized, 355 MW, and is being mated with a small regas terminal for 500,000 tons per annum (500 KTA) to supply 63 MMcfd to the engines. The plant is due to go into service in 2018.

As the Panama horse race comes into the final turn, it is turning into the most successful tender ever put forth in the CAC region. The frequent complaint is that severe bidding restrictions narrow the potential field of bidders down to where there is often only one bidder. In contrast, this tender, by the latest count, has at least seven bidders with proposed projects before the Autoridad Nacional de Servicios Publicos (ASEP), Panama's utility regulator. All have received "provisional licenses."

For our purposes, the only projects that matter are those proposing to run on some form of gas energy. Considering the fate of the last LNG plant proposal, we were surprised to see two LNG proposals crop up on ASEP's latest list. One proposed by Caribe NG Power, the 300-MW Gatun generating station, is sited at Cristobal, at the Atlantic entrance to the Canal. This one looks like a downsized version of the 670-MW plant killed last year.

The other is the 366-MW Termogas plant proposed by Grupo Energetico del Caribe. It is unclear from the ASEP list what plans these operators have to manage their gas supply, but it would seem inescapable that the power plant would need to be paired with a regas terminal. The El Salvador project suggests that the price tag for the combination is $900 million.

The big news since our Propane Turbine story is a proposal duly submitted to ASEP in July, and in receipt of a provisional license, for a 400-MW plant to run on ethane as its fuel. What makes this submission even more intriguing is the plan to power the generators with reciprocating engines provided by Wartsila. Taking a leaf from El Salvador's playbook, an innovative gas-fired plant will be built around old, reliable recips instead of gas turbines.

The ethane power plant proposal was put forward by Gator Partners and is named Energia Corotu. The proposal completely shakes up the scenario developed in the OPIS July 23 story. There, the prime movers were to be turbines, the fuel of choice was propane, and the location was moved from the Atlantic side of the Canal (Colon) to the Pacific side (Panama City) where there is high demand growth for electric power.

Scrap all that about moving the generating capacity to the Pacific side. Colon, the city of about 100,000 population on the Atlantic side, is the site of all the pending power projects in the queue to be considered for the Aug. 31 tender.

When considered as a geographical reference point, Colon has two sides. The front is the world port of Cristobal that faces the Atlantic entrance to the Canal. The back is in the marshes east of the city centered around the old Refineria Panama on a peninsula referred to as Bahia Las Minas. To get the lay of the land, Google Map users will get the most help by entering Puerto Pilon, Colon in the Map window.

In the roster of current project proposals, four are in front, sited in Cristobal or on Telfers Island just south of it. Of these, the most important is the 300-MW Gatun gas-fired plant, likely sited on the same plot as the canceled 670-MW LNG plant and regas terminal.

But the serious action is in back, where the bulk of Panama's existing thermal generating capacity of 1,150 MW is already located. The list is headed by the 280-MW Bahia Las Minas station owned by Engie (the renamed GDF Suez). The top four thermal facilities on the back side constitute 616 MW between them, 54% of the national thermal total.

No less than eight of the proposals in the current project queue are sited on the back side, three in Puerto Pilon, four in Cativa just to the west, and one in Sabanitas just to the south. The ones that matter here are both in Puerto Pilon: the 400-MW ethane-fired plant of Gator Partners, and the 366-MW Termogas gas-fired facility, presumably with LNG regas capability.

In the context of the main tender being run by ASEP, our sources predict that only one of the large facilities, 300 MW and up, now on the drawing board will come to fruition. By this calculus, the game is between one of the two LNG proposals, Gator's ethane-fired plant, and the 350-MW propane-fired plant described in the July 23 article but not showing in the ASEP list of projects with provisional licenses.

The liabilities of the LNG solution are already well-known. The regas terminal virtually doubles the capex required for the generating plant. The El Salvador budget of $900 million offers a handy benchmark for what a comparably-sized power plant and regas terminal would cost.

In this size range, 300-400 MW, the size appropriate for the CAC region, the advantages of a power plant fired by propane or ethane are compelling. Even at the OLD prices of ethane or propane, knocking 40% off the capital cost of the power plant would almost certainly make the discounted cash flow (DCF) for those plants well above what would be shown for the gas-LNG option.

But now, with ethane extraction economics destroyed, and ethane showing a negative netback at the gas plant, the utility buyer gets his ethane at fuel value, i.e., the equivalent of gas originating at Henry Hub.

And propane economics, for the gas processor, are little better. At last week's Mont Belvieu average price of 37.3ct/gal for propane ($15.21/bbl), against an average oil price of $43.21 for WTI, the propane-oil price ratio (POPR) stood at 36%, in contrast to an historical average over 70%. The gross propane frac spread was $1.26 per MMBtu (11.5cts/gal), which does not cover the logistic costs of getting the product to Mont Belvieu and getting it fractionated.

Granted, propane will not stay at this severely depressed level forever, and we would surmise that the POPR will recover to somewhere in the 40s during the fall and winter demand season. But at that level, the economics of a propane-fired power plant still runs rings around the LNG option. On a fuel-cost basis alone,Belvieu propane landed at Colon probably beats laid-in cost for LNG. When the capex difference is factored in, there is simply no contest.

All this brings us, finally, to the ethane-fired option. The preliminary price tag Gator Partners has put on its proposal is a super-cheap $400 million, $1 million per megawatt. We will surmise that they have not factored in the logistics costs of a fully refrigerated ethane terminal to receive the newly built ethane gas carriers now in development at the world's shipyards. So let's add on, say, $200 million for the fully-ref tanks and the dock to receive the ethane carriers.

Just in terms of raw project costs, we're looking at $900 million for the LNG option, maybe $600 million for the ethane option, maybe $500 million for the propane option. Again, for a propane-fired plant at Puerto Pilon, we need to factor in the costs of a propane terminal adjoining the power plant, but capex on that would be much lower than for the ethane terminal.

Can the Wartsila recip engines running on ethane do the job? A project finance consultant says those big recips, properly tuned, can run on anything, and they're way less temperamental than turbines. They may not run at quite as high an efficiency factor as the LM-6000 turbines discussed in the July 23 article. But the steady, trouble-free operation can probably make up for any deficiency in pure operating efficiency.

What about the economics of ethane imported from Mont Belvieu? The finance expert asks how they could get any better. Ethane is being extracted as a loss leader at gas plants from coast-to-coast. Hopefully propane will soon lift its head above breakeven extraction value to justify operating the gas plants. But North American ethane's long-term value (for the next 15 years) is likely to stay at or below extraction economics. Delivered at Puerto Pilon, it will be cheaper than the cost of gas from LNG delivered to the site.


August 17, 2015
Oxy Ingleside Startup Delayed by Pipeline Problems

Reports circulating among market sources indicate that problems with the NuStar pipeline spanning the distance from Mont Belvieu, Texas, to Ingleside, on Corpus Christi Bay, account for the miss on the startup date of Occidental's major propane export terminal at Ingleside.

Oxy's key partner in bringing the Ingleside terminal to fruition, since the initial announcement of the project in July 2013, has been NuStar Energy LP. NuStar's contribution to the project is an idle 12-inch pipeline, formerly in jet fuel service, that spans most of 235 miles from Mont Belvieu to Ingleside.

According to a two-year-old report in OPIS (July 25, 2013), Oxy's agreement with NuStar called for NuStar to reverse the pipeline to southbound flow and refurbish it for the higher pressure service needed for NGLs.

In a more recent OPIS update (March 24), Oxy expressed confidence that they would be able to hit their target of midyear loadout of the first cargo. At that time, the progress report was very favorable: "The key component on the pipeline project is the Midway Pump Station, in the vicinity of Port LaVaca, which was 75% complete on March 10."

The progress report OPIS viewed at the time set forth the timeline in the home-stretch: "Phase 2 commissioning commences on April 22 when propane first flows from a Mont Belvieu storage cavern into the pipeline. Pipeline commissioning from Mont Belvieu to Midway Station is expected to take about three weeks. Line fill and commissioning of the southern spread from Midway to Ingleside will bring propane to the terminal portal on June 1."

And then ... along came the Memorial Day deluge, torrential rains that began around May 15. This weather event had an outsized impact on the whole Gulf Coast, starting at Mont Belvieu. The deluge diluted the brine in Belvieu brine-ponds, making it temporarily unusable for injection into storage wells to get propane out. In the last week of May, a location differential of 5-6cts/gal opened up between Enterprise storage and the other Belvieu storages.

The deluge had a more severe impact on the NuStar-Ingleside program. Oxy declined to comment on reports in the grapevine, but OPIS has attempted to piece together a sequential account.

The main physical challenge from the rain was that most of the pipeline route, and the Midway Pump Station site, were underwater for two to three weeks from Memorial Day forward. Most of the pipe from Midway to Ingleside is new. The challenge was to assure that the old jet fuel line would be completely ready for LPG service when time for system startup came.

As line-fill operations got underway in June, and they were pressuring up the old line to start filling the tanks at Ingleside, grapevine sources say the line blew out in two places. The line-fill operation stopped abruptly of course, and NuStar and Oxy immediately went to Plan B.

Plan B was to push all the product then in the line on to the tanks at Ingleside, block the line off at Midway, and run hydrostatic tests on the entire length of the old line. NuStar had already been doing this for a long time, and some sections of the old line had been completely redone. But obviously some spreads that tested OK in the refurbishing phase did not pan out as usable.

Market sources pinpoint July 8 as the definitive date to load out the first cargo. In the early phases of Ingleside operation, they will not be in fully refrigerated mode, so instead of VLGC's, they will be loading Navigator handy-size vessels of roughly 12,000-ton (12 KT) capacity, or 150,000 bbl.

The first cargo was "force-majeured," as they say in the grapevine, and sources think it was rescheduled for August. Well, now, that one has been missed as well. In the meantime, NuStar is heavily engaged in exacting tests of every inch of the old line. If it all goes well, and the next attempt at pressuring up goes without a hitch, the hope is that they can hit loadout of the first cargo in 1stHalf of September.


 

Who Should Attend

  • Traders/Trader Apprentices
  • Brokers
  • Sales/Marketing Managers
  • Analysts
  • Logistics/Accounting Personnel
  • Schedulers
  • Transportation Managers
  • Petrochemical Professionals
  • Auditors
  • Ethanol Managers
  • Professionals involved with natural gas liquids