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In This Issue

NARUC 2017: Are the Days of Cheap Natural Gas Numbered?

Court Rejection of FERC’s Actions on PJM MOPR Filing Likely to Change FERC Decision Making

Natural Gas and Oil Market Update

EIA - Weekly Natural Gas Storage Report

NYMEX Natural Gas Week-to-Week Price Change

Natural Gas Futures - Five Year Price

Tables

NOAA 6 to 10 Day Outlook
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Color indicates the probability of forecasted temperatures being above or below a historical average for the period.

 


NARUC 2017: Are the Days of Cheap Natural Gas Numbered?

UtilityDive | July 20, 2017

Higher demand for gas could spark greater price volatility and spell bad news for the climate, analysts said.

If there’s one defining feature of the modern U.S. electricity sector, it’s low gas prices.

Since advances in fracking and horizontal drilling lowered the price of gas at the beginning of the decade, the fuel has taken the sector by storm. Last year, gas surpassed coal as the top power generation resource, and the low prices have enabled the coal-to-gas switching that’s responsible for most U.S. CO2 emission reductions to date.

At the summer meetings for the National Association of Regulatory Utility Commissions (NARUC) in San Diego this week, Suzanne Lemieux, manager of midstream operations for the American Petroleum Institute, put the supply boom into stark relief. Looking back at the 2012 EIA Annual Energy Outlook — an influential yearly energy report from the federal government — she said gas production over the past five years has exceeded even its most aggressive predictions.

“We’ve been able to outpace even the highest [estimated] case in production and that is largely due to the competitive nature of the oil and gas industry,” she said.

Looking ahead, Lemieux said EIA’s most recent projections see a continuation of cheap to moderately-priced gas for decades to come, cementing its role as a central generation resource: “Out to 2040, we still see a spread of between $3.40 to $5 [per mmBtu], so out to 2040 with available resources we still see an extremely competitive resource that we're able to extract.”

But those EIA estimates rely on some faulty assumptions, according to Andrew Weissman, founder of EBW Analytics, a market research firm.

“What studies do that I think is important to understand is essentially they assume you already know how much [gas] we're going to need, so producers can plan ahead of time,” he said. “What actually happens with natural gas prices though already … is that there are important portions of demand that can't be regularly predicted ... and that can cause very high levels of price volatility.”

Weissman cautioned conference attendees that coming changes in the export market and consumption from gas generators could create conditions for intense price spikes in the near future. And as that gas consumption increases, his brother — Steve Weissman of the Center for Sustainable Energy — warned that expanded use of the resource could push the U.S. over its two-degree carbon budget.

Volatility on the horizon

Even given the explosive growth of natural gas production in this decade, EBW’s Weissman said "we’re still at an early stage of the unprecedented growth in natural gas produced in the U.S.”

“We're likely to see at least a 20 bcf/day increase over the period of the next few years — it could be greater — triggered by increases across the board,” he said. “A lot of it is baked in with new combined cycle [gas generation] units being built right now and ... pipeline exports to Mexico, but perhaps the most important part is we are starting to see explosive growth in U.S. LNG export capability.”

There are more than $40 billion in new LNG export facilities currently being built, Weissman said — a stark contrast to a decade ago, when U.S. gas companies were configuring import terminals to bring in the resource from abroad.

While questions remain about how many facilities will be completed and what their utilization rates will be, “there's no question that there will be a tremendous increase in the demand for natural gas and we could see even more growth further down the line,” he added.

That could pose a problem for generators and gas utilities alike. Already, Weissman said, natural gas is prone to price volatility because it is expensive to store and most storage facilities exist to smooth out seasonal shifts in demand. Because winter demand for gas is difficult to predict — mostly contingent on weather — it’s easy for demand to outpace local supplies and lead to higher prices.

U.S. gas production is among the most nimble drilling industries in the world, but even it would take “the better part of a year” before it could respond to tight winter supplies with enhanced production, “so you may for a period of many months have sharp price spikes.”

The coming increases in gas demand driven by LNG exports could “multiply this volatility several-fold,” Weissman said.

Just two years from now, Weissman said NARUC could be holding panel discussions about “the severe price spikes in 2019” due to high demand for LNG and a cold winter worldwide.

While it’s just a hypothetical scenario, Weissman said you could see a situation where the primacy of U.S. LNG would mean that during periods of high domestic demand, “the local distribution utilities would have to bid against national energy companies around the world for scarce supply, driving up prices.”

Exacerbating the issue is the continued difficulty in siting natural gas infrastructure — particularly pipelines, which are stalled in New England due to citizen opposition — and the need for more gas storage, Weissman said.

“We do not have a plan to build all the natural gas pipeline infrastructure we’re going to need for the market to function typically by later in this decade,” he said, “and that could lead to price spikes and regional variations in gas prices.”

The climate question

EBW’s Weissman said gas can “play a major role” in moving to a deeply decarbonized grid, along with renewables, nuclear and other resources. But his brother, a senior policy advisor for the Center for Sustainable Energy and a former Administrative Law Judge for the California PUC, warned that the coming increase in gas demand could scuttle those climate efforts.

No one has pinpointed a time when they expect natural gas demand to begin to decrease, CSE’s Weissman said, and the continued build-out of gas infrastructure to meet it could mean more economic and political pressure to keep gas use rising.

“The history of the U.S. does not support the notion that as we move toward renewable energy that we're naturally going to put fossil fuels in the rearview,” he said. “We have to be more affirmative about how we're going to get to that point if that's where we're going to go.”

The problem is that while gas has contributed to carbon mitigation to date, it is still an emitting resource. And if the U.S. wants to move to a deeply decarbonized grid, gas will soon become an impediment, rather than a facilitator to that goal, assuming its carbon is not captured.

Using EIA estimates for gas demand out to 2050 — which tend to be conservative — Weissman said the resource could account for the U.S.’s entire carbon budget.

Assuming the U.S. wants to hit an economywide decarbonization target of 80% by 2050, “the question is what would that level of gas consumption do in terms of meeting a share of the overall budget of GHG emissions in 2050,” Weissman said. “The answer is — just from smokestack emissions alone, natural gas would take all of the available GHG emissions. Nothing left for agriculture, transportation or anything else.”

There are already some researchers who think we’ve already hit the point where gas could inhibit decarbonization. Writing in the journal Applied Energy last year, Oxford researchers said that due to the long life of fossil fuel assets, “no new investment in fossil electricity infrastructure (without carbon capture) is feasible from 2017 at the latest” if we are to hit the targets of the Paris climate accord.

Weissman said the situation may be even more dire. While most studies assume a 25 to 30 year life for natural gas assets, many plants on the system today “are far in excess of that age in terms of operation.”

He said his team looked at the lifespan of natural gas plants in California, trying to ascertain how long a typical generator could stay online.

“The question was if someone was to step forward today and say to you we're thinking of building a natural gas plant, what should you have in mind in terms of how long there's going to be economic and political pressure to keep that plant operating?” he said. “What we found was that if combined cycle units of the future are behaving in the same way that these plants have historically behaved, you should expect that … even in the best of circumstances … you can expect that plant to be operating beyond 2050.”

That’s bad news for the climate, Wiessman said, and regulators should take those implications into account when they evaluate siting for new natural gas infrastructure. “Even if that's all you do, having that [perspective] available and to reflect on that as you make new infrastructure decisions and new rate setting decisions should help ... increase the extent to which we move from just hoping the market is going to take care of natural gas for us and start to more directly plan.”

Not all the attendees at the NARUC gas panel were keen to heed Weissman’s call for a planned drawdown in natural gas consumption. Maine PUC Commissioner Bruce Williamson argued that market forces are responsible for the current boom in gas production and clean energy. “God help us” if regulators try to plan the transition, he said, triggering applause around the room.

Weissman replied that while markets sparked the gas boom, relying on them to guide the rest of the transition will mean “it's pretty likely we're going to continue to use fossil fuels.”

“I think what's going to happen is the more go about renewables, for instance, the lower the price is going to be for fossil fuels,” he said. “There's going to continue to seem to be an economic imperative to continue to use fossil fuels because we will be concerned that if we don’t, we will drive up the price of electricity, for instance, unnecessarily. So, yes, I think the planning is a way to break this pattern that we've been seeing.”

Read More:
http://www.utilitydive.com/news/naruc-2017-are-the-days-of-cheap-natural-gas-numbered/447437/


Court Rejection of FERC’s Actions on PJM MOPR Filing Likely to Change FERC Decision Making

On July 7, 2017, the U.S. Court of Appeals for the District of Columbia Circuit rejected Federal Energy Regulatory Commission (FERC) actions modifying PJM’s Minimum Offer Price Rule filing. NRG Power Marketing, LLC, et al. v. FERC, No. 15-1452 (July 7, 2017). The court said FERC’s modifications violated FERC Section 205 of the Federal Power Act (FPA). The modifications were major — because they “transform[ed] the [PJM] proposal into an entirely new rate of FERC’s own making”1 — and FERC cannot approve major modifications to an electric utility filing under Section 205 even if the filing party [PJM here] consents to FERC’s major modifications. The court’s decision will have significant ramifications, in particular by limiting FERC’s ability to significantly modify rate proposals by electric utilities under Section 205 as well as interstate pipelines under Section 4 of the Natural Gas Act.

PJM’s “Minimum Offer Price Rule” (MOPR) requires new generators to submit capacity auction bids at or above a price floor established by PJM. The rule is intended to prevent new generators (whose costs may be subsidized) from artificially depressing the auction’s “clearing price” and in turn sending inaccurate market signals.

Prior to 2012, PJM’s MOPR had two key features, (1) a unit specific review under which a generator could bid below the price floor if it could demonstrate that its costs were below the price floor; and (2) a one-year mitigation period if generator failed the unit specific review. In 2012, both generators and load serving entities agreed to get rid of the unit specific review, replacing it with only two categories of new generation that could bid below its costs, (i) competitive entry (generation either unsubsidized or subsidized through a process in which all could compete) and (ii) self-supply (load that meets a portion of their electricity by generating their own electricity.) Further, generator and load serving entities agreed to extend the mitigation period for generation that did not fit into these two categories from one year to three years.

PJM filed those changes, what the court referred to throughout as a “compromise”2 at FERC. While FERC approved the compromise proposal, it also modified the compromise proposal. FERC approved the two categories but required PJM to retain the unit specific review. Further FERC rejected the three-year mitigation period, requiring the mitigation period for any generation subject to the MOPR unit to remain at one year. PJM agreed to the revisions. NRG Energy and others appealed. The court vacated3 FERC’s modifications with respect to “unit-specific review, the competitive entry exemption, the self-supply exemption, and the mitigation period”4 and remanded the matter to FERC.

To understand the court’s decision, one must understand the purpose of Section 205 of the FPA from a rate-payer perspective [in this case NRG, et. al.,] and FERC’s role in administering that section. Section 205 gives notice to ratepayers of a rate change by the filing utility and the opportunity for those affected to comment on that change. FERC plays a “passive and reactive role.”5 In that role, FERC may either accept or reject a proposal but FERC cannot make modifications to a proposal that are major, i.e., modifications that transform the proposal “into an entirely new rate of FERC’s own making.”6

In this case, FERC’s modifications were major, in part,7 because they went in the opposite direction than the compromise proposal filed by PJM. PJM’s proposal limited the MOPR exemptions to two categories, i.e., the MOPR would apply to all new generation unless the generation fell into one of those two categories, and required mitigation of units not falling into these two categories for three years, instead of one.

FERC, however, expanded the MOPR exemptions by (i) layering the unit-specific review on top of the two new categories and (ii) limiting the requirement to bid at the price floor to one year instead of three years. FERC’s modifications — what the court referred to as a “rejection-plus-proposal action by FERC”8 — removed FERC from the “passive and reactive role” envisioned by § 205.

These major modifications also deprived customers of “notice” of the modifications approved and the opportunity to comment on those proposals. As the court said, “Generators and Load Serving Entities had an opportunity to comment on the original compromise proposal submitted by PJM. But they did not have an opportunity to comment on FERC’s modifications before FERC issued its decision. They also did not have an adequate opportunity to comment on the request for rehearing.”9

PJM’s consent to those modifications did not insulate FERC from violating Section 205 or remedy the harm caused by depriving generators and load serving entities notice of FERC’s proposed modifications. Under Section 205, a utility can consent to minor changes because the original filing, with the addition of minor modifications, remains intact. But when FERC makes major modifications, proposes its “own original notion of a new form of rate,” the utility’s consent does not excuse a Section 205 violation because the customers are not notified in advance of those major modifications and cannot comment. As the court said:

In those circumstances [where FERC makes major modifications to a proposal], the utility’s consent is inadequate because consent does not cure the harms to the utility’s customers. Section 205 protects the utility’s customers by ensuring “early notice — in the rate proposal itself — of the sort of rate increase that is sought.” When FERC “imposes an entirely new rate scheme” in response to a utility’s proposal, the utility’s customers do not have adequate notice of the proposed rate changes or an adequate opportunity to comment on the proposed changes.10
Further PJM’s stakeholders “could not fully contest FERC’s modifications with new evidence on rehearing.11Thus, the court concluded, “PJM’s stakeholders lacked the protections provided by Section 205. PJM’s consent did not restore those protections.”12

The court’s decision will have significant ramifications for market participants on a number of different levels.

First, the decision will affect FERC’s review of interstate pipeline filings under Section 4 of the Natural Gas Act (as well as Section 205 of the Federal Power Act.) Section 4 and Section 205 are drafted similarly — with the same passive and reactive role for FERC and notice and ability to comment for ratepayers — and decisions under Section 205 are equally applicable to Section 4 of the Natural Gas Act.13

Second, the decision will have a significant impact on FERC decision making. While the decision will stop FERC from significantly modifying a utility or pipeline proposals, it will likely result in FERC rejecting more proposals. If FERC can’t make major modifications to a utility or pipeline filing, even if the utility or pipeline might consent, then FERC will likely reject the proposal and at the same time tell the pipeline or utility that the proposal would be accepted if these changes were made. Further, FERC practitioners will likely argue over — and FERC will have to decide — whether FERC’s modifications were major, i.e., whether FERC imposed its “own original notion of a new form of rate” or minor, and thus whether or not the utility or pipeline can consent to those changes.

Third, there is the potential for rerunning or redoing the PJM capacity auctions previously held that were affected by the major modifications the court found violated Section 205. While market participants, including generators, are generally loathe to rerun/redo auctions after the fact, such a redo/rerun is a possibility here under two scenarios.

If a court finds that FERC acted illegally, FERC can put the parties back in the position they would have been but for the illegal FERC action.14 Applying that principle to the PJM capacity auctions, if an auction was held (i) in which a generator bid below the price floor either because it used the unit specific review or the one year mitigation had ended and (ii) generator’s bid affected the market clearing price, then on remand the FERC could require that the auction be rerun/redone without that generator’s bid.

Further, because the court vacated the commission’s orders, the net effect is that the orders never existed and the existing MOPR rules were reinstated.15 Thus there would be no self-supply exemption or competitive supply exemption — the only operative exemption from the MOPR would be the unit specific exemption. If a self-supply or competitive supply generator (i) would not pass the unit specific review and (ii) the generator’s bid affected the market clearing price, then on remand the FERC could require that the auction be rerun/redone without that generator’s bid.

Read More:
http://www.lexology.com/library/detail.aspx?g=03558f79-a3ac-4a4f-8cec-6dc7c44b10b1

Natural Gas and Oil Market Update

Arrow

Oil Retreats From 6-Week High As Traders Await Producer Meeting

MarketWatch | July 20, 2017

Oil pulled back Thursday, a day after a third consecutive weekly declines in U.S. crude supplies lifted prices to a six-week high.

Traders weighed outcome scenarios for a crucial meeting of some of the world’s biggest producers next week.

The August contract for West Texas Intermediate crude CLQ7, -0.83% which expired at the day’s settlement, fell 33 cents, or 0.7%, to finish at $46.79 a barrel on the New York Mercantile Exchange. The new front-month contract, September WTI oil CLU7, +0.15% ended at $46.92, down 40 cents, or 0.9%.

  Arrow

U.S. Natural Gas Futures Rise To 3-Week High After Weekly Storage Data

Investing.com | July 20, 2017

U.S. natural gas futures rose to a fresh three-week high on Thursday, after data showed that domestic supplies in storage rose less than anticipated last week.

U.S. natural gas for August delivery rose to a session high of $3.110 per million British thermal units, its highest since June 29. It was last at $3.085 by 10:50AM ET (1450GMT), up 1.9 cents, or around 0.6%. Futures were at around $3.110 prior to the release of the supply data.

Prices finished lower for the first time in four sessions on Wednesday.


EIA - Weekly Natural Gas Storage Report

EIA - Weekly Natural Gas Storage Report

Summary
Working gas in storage was 2,973 Bcf as of Friday, July 14, 2017, according to EIA estimates. This represents a net increase of 28 Bcf from the previous week. Stocks were 299 Bcf less than last year at this time and 141 Bcf above the five-year average of 2,832 Bcf. At 2,973 Bcf, total working gas is within the five-year historical range.

NYMEX Natural Gas Week-to-Week Price Change NYMEX Natural Gas Week-to-Week Price Change

Natural Gas Futures - Five Year Price ($ per mmBtu)

NYMEX Natural Gas Week-to-Week Price Change - Five Yearly Snapshot

Disclaimer: The information contained in these reports is gathered from public and/or internal sources and is presented solely for the convenience of our customers and Newsletter Subscribers. Patriot Energy Group makes no representation or warranty, express or implied as to the accuracy or completeness of the information set forth in this newsletter, and Patriot Energy shall not have any liability to any person or entity resulting from use of this information in any way.
 
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