In the 1930s, physicians approached the mental illness of depression a bit differently that we do today. While acknowledging a likely cause of depression in one of their patients is often due to some great misfortune, they seemed to focus on what is called a complex. A complex is disturbances of ideas and impulses that are the cause of consistent habitual patterns of thought, feelings, and behavior.
An example of this state of mind of one who is depressed is one who experiences an exaggerated or obsessive concern or fear. And the etiology for this mental disorder was often undefined. People react differently to life stressors in their life, so depression cannot be empirically determined.
Also in the 1930s, psychotherapy such as cognitive therapy was recommended for treating the depressed patient, and not pharmacological therapy. Also considered for the depressed patient was positive lifestyle changes that would lessen the pain that the depression was causing them. Try and be grateful, they would tell their patient, as well as thankful and appreciative for whatever good may be in their life, and normally the depressed patient would eventually recover.
Presently, serotonin-enhancing drugs are the therapeutic regimens for those who are suspect of having a depressed state or mood disorder. Patients believing they have such cognitive issues often ask for such medications. The drugs are known as SSRIs, or SRNIs.
What is remarkable is that the mood disorders which will be discussed later are subject to debate. Yet such disorders have been brought to the attention to so many others through disease awareness campaigns by the makers of these classes of drugs. So mental flaws claimed to be relieved by SSRI drugs may not be entirely accurate.
With depression, the most severe cognitive and behavioral malfunctions are expressed in what is called a major depressive disorder, which is also called clinical depression or major depression.
Symptoms of this type of depression, which is the most concerning to health care providers in particular due to its severity, include decreased or flat affect, decreased interest in activities once enjoyable, self perceptions of worthiness, guilt, regret, helplessness, and hopeless by the sufferer, to name a few of the diagnostic features that may be present with one who has such a major depressive disorder.
These SSRI drugs mentioned earlier are known by some health care providers as third generation anti-depressants. Such drugs, drugs that affect the mind, are called psychotropic medications. SSRIs also include a few drugs in this class that include the addition of a norepinephrine uptake inhibitor added to the SSRI in one capsule, and these drugs are referred to as SNRI medications. The combination of two different drugs has made them the top class of prescriptions for those suspected of psychological misalignment.
There are several available SSRIs presently, and a few SRNIs. Both classes of medications are prescribed for similar mental conditions.
Some consider these classes of meds, the serotonin enhancers in these medications, to be the next generation mood enhancers- after the benzodiazepine hype decades ago, which was followed by what were called trycyclic drugs for depression for some time as well, it is believed.
Furthermore, regarding SNRIs, adding the additional agent of norepinepherine is presumed to increase the effectiveness of SSRIs by some, yet not everyone claims relief from these types of drugs included in the SRNI class.
Serotonin is a neurotransmitter thought to be associated with mood. The hypothesis was first suggested in the mid 1960s that this neurotransmitter may play a role in moods and emotions in humans. Yet to this day, the serotonin correlation with such behavioral and mental conditions is only theoretical.
In fact, the psychiatrist's bible, which is known as the DSM, states that the definite etiology of depression remains a mystery and remains unknown with complete certainty. So a chemical imbalance in the brain is not proven to be the cause of mood disorders, it is only suspected as a result of limited scientific evidence. Diagnosing mental diseases such as depression is based on subjective assessment only, as interpreted by the prescriber, so one can examine the accuracy of such diagnoses.
So such speculated mental illnesses can only be assessed conceptually. As a result, the diagnosis or impression concluded by the patient's health care provider is dependent on subjective criteria expressed by the suspected patient that is presumed to be not mentally sound.
At times, there have been screening programs that have been used for identifying depressed patients have proven to be largely ineffective.
A social patient history is uncertain and tricky as well, some have said, yet is obtained often from such patients. There is no objective diagnostic testing for any mental malfunction to validate as to whether or not such a disease is present- just the perception of the health care provider, and survey questions related to a particular mental disorder.
A health care provider has to assess as to whether certain non-verbal or vocalized features are present with a patient in order to conclude confidently that one may have in fact some degree or level of depression or any other mental disorder.
To assess a suspected depressed patient is further complicated by the fact that the exact cause of major depression is unknown. Research says that there is a strong genetic component to this illness, however.
The diagnosis of depression as well as mood disorders that may exist within patients has increased quite a bit over the past few decades. Some have asked themselves, as well as others- actually how many people are really and actually depressed, or affected by any other mental disorder?
What is believed is that if one determined to be cognitively impaired from a mental paradigm, then this may be in fact major depression. If this mental disorder is determined by a health care provider, it is possible that pharmacological therapy may be considered reasonable and necessary, as well as psychotherapy either suggested to be performed with or in place of medicinal therapy.
It has been reported that around 10 percent of the U.S. population will at some point be affected by an episode of what may be a major depressive disorder. This is much greater in number than just a few decades ago.
Perhaps media sources are to blame to some degree for the progressive increase in diagnosing mental disorders by suggesting to the public that they may have such disorders. So the diagnosis and medicinal treatment have clearly increased in a relatively short period of time in the United States. Of course, the expansion of those claimed and determined to be depressed does not sadden the makers of these drugs used to treat this mental disorder one bit, it is safe to say.
In regards to those pharmaceutical companies who make and market such psychotropic drugs in the manner that their manufacturers do is largely unknown to others, such as with screenings performed essentially by front groups, and so forth.
However, what is known is that the psychiatry specialty, as they often treats and manages depressed patients, is the one specialty that receives the most monetary funding that is paid to them by these certain pharmaceutical companies for ultimately what they hope will be continued and additional support of the psychotropic meds that they currently promote to these doctors.
Presently, there are about ten different SSRI/SRNI meds available, many of which are now generic, yet essentially, they appear to be similar in regards to their efficacy and adverse events.
The newest one, a SNRI called Pristiq, was approved in 2008, and is believed to be launched as a treatment for menopause.
Perhaps of greater concern and danger with these particular psychotropic medications involve the adverse effects associated with these types of drugs, which include suicidal thoughts and actions, violence- including acts of homicide, and aggression- and this is only to name a few. Such events are devastating and have been demonstrated by those who have or are taking these types of drugs.
It has been reported that the makers of such drugs are suspected to have known about these toxic and dangerous effects of their drugs and did not share them with the public in a timely and critical manner until forced to do so.
The makers of Paxil caught the attention of the government regarding this issue of data suppression some time ago, this hiding of such important information- Elliot Spitzer specifically was the catalyst for this awareness, as I recall.
Furthermore, that drug is in the spotlight once again years later. Some believe the drug maker knew about possible risk to the youth as early as 1991. Yet did not disclose such danger associated with their drug to the public or the FDA, and this was done with intent.


A warm and uplifting Americana style track with fingerpicked acoustic guitars, piano, bass and drums. The track has a light and comfortable feel that will easily blend with many moods.
Folky strummed feel-good acoustic guitar, with verse and chorus sections.


text:
Tag Archives: PCIA
Why are we punishing customers for doing the right thing?
The saying goes "No good deed goes unpunished." The California Public Utilities Commission seems to have taken that motto to heart recently, and stands ready to penalize yet another group of customers who answered the clarion call to help solve the state's problems by radically altering the rules for solar rooftops. Here's three case studies of recent CPUC actions that undermine incentives for customers to act in the future in response to state initiatives: (1) farmers who invested in response to price incentives, (2) communities that pursued renewables more assertively, and (3) customers who installed solar panels.
Agriculture: Farmers have responded to past time of use (TOU) rate incentives more consistently and enthusiastically than any other customer class. Instead of being rewarded for their consistency, their peak price periods shifted from the afternoon to the early evening. Growers face much more difficulty in avoiding pumping during that latter period.
Since TOU rates were introduced to agricultural customers in the late 1970s, growers have made significant operational changes in response to TOU differentials between peak and off-peak energy prices to minimize their on-peak consumption. These include significant investments in irrigation equipment, storage and conveyance infrastructure and labor deployment rescheduling. The results of these expenditures are illustrated in the figure below, which shows how agricultural loads compare with system-wide load on a peak summer weekday in 2015, contrasting hourly loads to the load at the coincident peak hour. Both the smaller and larger agricultural accounts perform better than a range of representative rate schedules. Most notably agriculture's aggregate load shape on a summer weekday is inverted relative to system peak, i.e., the highest agricultural loads occur during the lowest system load periods, in contrast with other rate classes.
All other rate schedules shown in the graphic hit their annual peak on the same peak day within the then-applicable peak hours of noon to 6 p.m. In contrast, agriculture electricity demand is less than 80% of its annual peak during those high-load hours, with its daily peak falling outside the peak period. Agriculture's avoidance of peak hours occurred during the summer agricultural growing season, which coincided with peak system demand—just as the Commission asked customers to do. The Commission could not ask for a better aggregate response to system needs; in contrast to the profiles for all of the other customer groups, agriculture has significantly contributed to shifting the peak to a lower cost evening period.
The significant changes in the peak period price timing and differential that the CPUC adopted increases uncertainty over whether large investments in high water-use efficiency microdrip systems – which typically cost $2,000 per acre–will be financially viable. Microdrip systems have been adopted widely by growers over the last several years—one recent study of tomato irrigation rates in Fresno County could not find any significant quantity of other types of irrigation systems. Such systems can be subject to blockages and leaks that are only detectable at start up in daylight. Growers were able to start overnight irrigation at 6 p.m. under the legacy TOU periods and avoid peak energy use. In addition, workers are able to end their day shortly after 6 p.m. and avoid nighttime accidents. Shifting that load out of the peak period will be much more difficult to do with the peak period ending after sunset.
Contrary to strong Commission direction to incent customers to avoid peak power usage, the shift in TOU periods has served to penalize, and reverse, the great strides the agricultural class has made benefiting the utility system over the last four decades.
Community choice aggregators: CCAs were created, among other reasons, to develop more renewable or "green" power. The state achieved its 2020 target of 33% in large part because of the efforts of CCAs fostered through offerings of 50% and 100% green power to retail customers. CCAs also have offered a range of innovative programs that go beyond the offerings of PG&E, SCE and SDG&E.
Nevertheless, the difficulty of reaching clean energy goals is created by the current structure of the PCIA. The PCIA varies inversely with the market prices in the market–as market prices rise, the PCIA charged to CCAs and direct access (DA) customers decreases. For these customers, their overall retail rate is largely hedged against variation and risk through this inverse relationship.
The portfolios of the incumbent utilities are dominated by long-term contracts with renewables and capital-intensive utility-owned generation. For example, PG&E is paying a risk premium of nearly 2 cents per kilowatt-hour for its investment in these resources. These portfolios are largely impervious to market price swings now, but at a significant cost. The PCIA passes along this hedge through the PCIA to CCAs and DA customers which discourages those latter customers from making their own long term investments. (I wrote earlier about how this mechanism discouraged investment in new capacity for reliability purposes to provide resource adequacy.)
The legacy utilities are not in a position to acquire new renewables–they are forecasting falling loads and decreasing customers as CCAs grow. So the state cannot look to those utilities to meet California's ambitious goals–it must incentivize CCAs with that task. The CCAs are already game, with many of them offering much more aggressive "green power" options to their customers than PG&E, SCE or SDG&E.
But CCAs place themselves at greater financial risk under the current rules if they sign more long-term contracts. If market prices fall, they must bear the risk of overpaying for both the legacy utility's portfolio and their own.
Solar net energy metered customers: Distributed solar generation installed under California's net energy metering (NEM/NEMA) programs has mitigated and even eliminated load and demand growth in areas with established customers. This benefit supports protecting the investments that have been made by existing NEM/NEMA customers. Similarly, NEM/NEMA customers can displace investment in distribution assets. That distribution planners are not considering this impact appropriately is not an excuse for failing to value this benefit. For example, PG&E's sales fell by 5% from 2010 to 2018 and other utilities had similar declines. Peak loads in the CAISO balancing authority reach their highest point in 2006 and the peak in August 2020 was 6% below that level.
Much of that decrease appears to have been driven by the installation of rooftop solar. The figure above illustrates the trends in CAISO peak loads in the set of top lines and the relationship to added NEM/NEMA installations in the lower corner. It also shows the CEC's forecast from its 2005 Integrated Energy Policy Report as the top line. Prior to 2006, the CAISO peak was growing at annual rate of 0.97%; after 2006, peak loads have declined at a 0.28% trend. Over the same period, solar NEM capacity grew by over 9,200 megawatts. The correlation factor or "R-squared" between the decline in peak load after 2006 and the incremental NEM additions is 0.93, with 1.0 being perfect correlation. Based on these calculations, NEM capacity has deferred 6,500 megawatts of capacity additions over this period. Comparing the "extreme" 2020 peak to the average conditions load forecast from 2005, the load reduction is over 11,500 megawatts. The obvious conclusion is that these investments by NEM customers have saved all ratepayers both reliability and energy costs while delivering zero-carbon energy.
The CPUC now has before it a rulemaking in which the utilities and some ratepayer advocates are proposing to not only radically reduce the compensation to new NEM/NEMA customers but also to change the terms of the agreements for existing ones.
One of the key principles of providing financial stability is setting prices and rates for long-lived assets such as solar panels and generation plants at the economic value when the investment decision was made to reflect the full value of the assets that would have been acquired otherwise. If that new resource had not been built, either a ratebased generation asset would have been constructed by the utility at a cost that would have been recovered over a standard 30-year period or more likely, additional PPAs would have been signed. Additionally, the utilities' investments and procurement costs are not subject to retroactive ratemaking under the rule prohibiting such ratemaking and Public Utilities Code Section 728, thus protecting shareholders from any risk of future changes in state or Commission policies.
Utility customers who similarly invest in generation should be afforded at least the same assurances as the utilities with respect to protection from future Commission decisions that may diminish the value of those investments. Moreover, customers do not have the additional assurances of achieving a certain net income so they already face higher risks than utility shareholders for their investments.
Generators are almost universally afforded the ability to recover capital investments based on prices set for multiple years, and often the economic life of their assets. Utilities are able to put investments in ratebase to be recovered at a fixed rate of return plus depreciation over several decades. Third-party generators are able to sign fixed price contracts for 10, 20, and even 40 years. Some merchant generators may choose to sell only into the short-term "hourly" market, but those plants are not committed to selling whenever the CAISO demands so. Generators are only required to do so when they sign a PPA with an assured payment toward investment recovery.
Ratepayers who make investments that benefit all ratepayers over the long term should be offered tariffs that provide a reasonable assurance of recovery of those investments, similar to the PPAs offered to generators. Ratepayers should be able to gain the same assurances as generators who sign long-term PPAs, or even utilities that ratebase their generation assets, that they will not be forced to bear all of the risk of investing of clean self-generation. These ratepayers should have some assurance over the 20-plus year expected life of their generation investment.
This entry was posted in Energy innovation and tagged agriculture, California, CCA, CPUC, distributed energy resources, electricity, energy economics, M.Cubed, PCIA, PG&E, solar rooftop on November 30, 2021 by Richard McCann.
Part 2: A response to "Is Rooftop Solar Just Like Energy Efficiency?"
Severin Borenstein at the Energy Institute at Haas has written another blog post asserting that solar rooftop rates are inefficient and must changed radically. (I previously responded to an earlier post.) When looking at the efficiency of NEM rates, we need to look carefully at several elements of electricity market and the overall efficiency of utility ratemaking. We can see that we can come to a very different conclusion.
I filed testimony in the NEM 3.0 rulemaking last month where I calculated the incremental cost of transmission investment for new generation and the reduction in the CAISO peak load that looks to be attributable to solar rooftop.
Using FERC Form 1 and CEC powerplant data, I calculated that the incremental cost of transmission is $37/MWH. (And this is conservative due to a couple of assumptions I made.) Interestingly, I had done a similar calculation for AEP in the PJM interconnect and also came up with $37/MWH. This seems to be a robust value in the right neighborhood.
Load growth in California took a distinct change in trend in 2006 just as solar rooftop installations gained momentum. I found a 0.93 correlation between this change in trend and the amount of rooftop capacity installed. Using a simple trend, I calculated that the CAISO load decreased 6,000 MW with installation of 9,000 MW of rooftop solar. Looking at the 2005 CEC IEPR forecast, the peak reduction could be as large as 11,000 MW. CAISO also estimated in 2018 that rooftop solar displaced in $2.6 billion in transmission investment.
When we look at the utilities' cost to acquire renewables and add in the cost of transmission, we see that the claim that grid-scale solar is so much cheaper than residential rooftop isn't valid. The "green" market price benchmark used to set the PCIA shows that the average new RPS contract price in 2016 was still $92/MWH in 2016 and $74/MWH in 2017. These prices generally were for 30 year contracts, so the appropriate metric for comparing a NEM investment is against the vintage of RPS contracts signed in the year the rooftop project was installed. For 2016, adding in the transmission cost of $37/MWH, the comparable value is $129/MWH and in 2017, $111/MWH. In 2016, the average retail rates were $149/MWH for SCE, $183/MWH for PG&E and $205/MWH for SDG&E. (Note that PG&E's rate had jumped $20/MWH in 2 years, while SCE's had fallen $20/MWH.) In a "rough justice" way, the value of the displaced energy via rooftop solar was comparable to the retail rates which reflect the value of power to a customer, at least for NEM 1.0 and 2.0 customers. Rooftop solar was not "multiples" of grid scale solar.
These customers also took on investment risk. I calculated the payback period for a couple of customers around 2016 and found that a positive payback was dependent on utility rates rising at least 3% a year. This was not a foregone conclusion at the time because retail rates had actually be falling up to 2013 and new RPS contract prices were falling as well. No one was proposing to guarantee that these customers recover their investments if they made a mistake. That they are now instead benefiting is unwarranted hubris that ignores the flip side of the importance of investment risk–that investors who make a good efficient decision should reap the benefits. (We can discuss whether the magnitude of those benefits are fully warranted, but that's a different one about distribution of income and wealth, not efficiency.)
Claiming that grid costs are fixed immutable amount simply isn't a valid claim. SCE has been trying unsuccessfully to enact a "grid charge" with this claim since at least 2006. The intervening parties have successfully shown that grid costs in fact are responsive to reductions in demand. In addition, moving to a grid charge that creates a "ratchet effect" in revenue requirements where once a utility puts infrastructure in place, it faces no risk for poor investment decisions. On the other hand the utility can place its costs into ratebase and raise rates, which then raises the ratchet level on the fixed charge. One of the most important elements of a market economy that leads to efficient investment is that investors face the risk of not earning a return on an investment. That forces them to make prudent decisions. A "ratcheted" grid charge removes this risk even further for utilities. If we're claiming that we are creating an "efficient" pricing policy, then we need to consider all sides of the equation.
The point that 50% of rooftop solar generation is used to offset internal use is important–while it may not be exactly like energy efficiency, it does have the most critical element of energy efficiency. That there are additional requirements to implement this is of second order importance, Otherwise we would think of demand response that uses dispatch controls as similarly distinct from EE. Those programs also require additional equipment and different rates. But in fact we sum those energy savings with LED bulbs and refrigerators.
An important element of the remaining 50% that is exported is that almost all of it is absorbed by neighboring houses and businesses on the same local circuit. Little of the power goes past the transformer at the top of the circuit. The primary voltage and transmission systems are largely unused. The excess capacity that remains on the system is now available for other customers to use. Whether investors should be able to recover their investment at the same annual rate in the face of excess capacity is an important question–in a competitive industry, the effective recovery rate would slow.
Finally, public purpose program (PPP) and wildfire mitigation costs are special cases that can be simply rolled up with other utility costs.
The majority of PPP charges are a form of a tax intended for income redistribution. That function is admirable, but it shows the standard problem of relying on a form of a sales tax to finance such programs. A sales tax discourages purchases which then reduces the revenues available for income transfers, which then forces an increase in the sales tax. It's time to stop financing the CARE and FERA programs from utility rates.
Wildfire costs are created by a very specific subclass of customers who live in certain rural and wildlands-urban interface (WUI) areas. Those customers already received largely subsidized line extensions to install service and now we are unwilling to charge them the full cost of protecting their buildings. Once the state made the decision to socialize those costs instead, the costs became the responsibility of everyone, not just electricity customers. That means that these costs should be financed through taxes, not rates.
Again, if we are trying to make efficient policy, we need to look at the whole. It is is inefficient to finance these public costs through rates and it is incorrect to assert that there is an inefficient subsidy created if a set of customers are avoiding paying these rate components.
This entry was posted in Energy innovation and tagged California, electricity markets, electricity rates, Energy Institute at Haas, market price benchmark, PCIA, solar rooftop, transmission, UC Energy Institute on July 21, 2021 by Richard McCann.
How to increase renewables? Change the PCIA
California is pushing for an increase in renewable generation to power its electrification of buildings and the transportation sector. Yet the state maintains a policy that will impede reaching that goal–the power cost indifference adjustment (PCIA) rate discourages the rapidly growing community choice aggregators (CCAs) from investing directly in new renewable generation.
As I wrote recently, California's PCIA rate charged as an exit fee on departed customers is distorting the electricity markets in a way that increases the risk of another energy crisis similar to the debacle in 2000 to 2001. An analysis of the California Independent System Operator markets shows that market manipulations similar to those that created that crisis likely led to the rolling blackouts last August. Unfortunately, the state's energy agencies have chosen to look elsewhere for causes.
The even bigger problem of reaching clean energy goals is created by the current structure of the PCIA. The PCIA varies inversely with the market prices in the market–as market prices rise, the PCIA charged to CCAs and direct access (DA) customers decreases. For these customers, their overall retail rate is largely hedged against variation and risk through this inverse relationship.
The portfolios of the incumbent utilities, i.e., Pacific Gas and Electric, Southern California Edison and San Diego Gas and Electric, are dominated by long-term contracts with renewables and capital-intensive utility-owned generation. For example, PG&E is paying a risk premium of nearly 2 cents per kilowatt-hour for its investment in these resources. These portfolios are largely impervious to market price swings now, but at a significant cost. The PCIA passes along this hedge through the PCIA to CCAs and DA customers which discourages those latter customers from making their own long term investments. (I wrote earlier about how this mechanism discouraged investment in new capacity for reliability purposes to provide resource adequacy.)
The best solution is to offer CCAs the opportunity to make a fixed or lump sum exit fee payment based on the market value of the legacy utility's portfolio at the moment of departure. This would untie the PCIA from variations in the future market prices and CCAs would then be constructing a portfolio that hedges their own risks rather than relying on the implicit hedge embedded in the legacy utility's portfolio. The legacy utilities also would have to manage their bundled customers' portfolio without relying on the cross subsidy from departed customers to mitigate that risk.
This entry was posted in Energy innovation and tagged California, CCA, electricity rates, electrification, PCIA, PG&E, renewables, RPS, SCE on February 2, 2021 by Richard McCann.
The PCIA is heading California toward another energy crisis
The California ISO Department of Market Monitoring notes in its comments to the CPUC on proposals to address resource adequacy shortages during last August's rolling blackouts that the number of fixed price contracts are decreasing. In DMM's opinion, this leaves California's market exposed to the potential for greater market manipulation. The diminishing tolling agreements and longer term contracts DMM observes is the result of the structure of the power cost indifference adjustment (PCIA) or "exit fee" for departed community choice aggregation (CCA) and direct access (DA) customers. The IOUs are left shedding contracts as their loads fall.
The PCIA is pegged to short run market prices (even more so with the true up feature added in 2019.) The PCIA mechanism works as a price hedge against the short term market values for assets for CCAs and suppresses the incentives for long-term contracts. This discourages CCAs from signing long-term agreements with renewables.
The PCIA acts as an almost perfect hedge on the retail price for departed load customers because an increase in the CAISO and capacity market prices lead to a commensurate decrease in the PCIA, so the overall retail rate remains the same regardless of where the market moves. The IOUs are all so long on their resources, that market price variation has a relatively small impact on their overall rates.
This situation is almost identical to the relationship of the competition transition charge (CTC) implemented during restructuring starting in 1998. Again, energy service providers (ESPs) have little incentive to hedge their portfolios because the CTC was tied directly to the CAISO/PX prices, so the CTC moved inversely with market prices. Only when the CAISO prices exceeded the average cost of the IOUs' portfolios did the high prices become a problem for ESPs and their customers.
As in 1998, the solution is to have a fixed, upfront exit fee paid by departing customers that is not tied to variations in future market prices. (Commissioner Jesse Knight's proposal along this line was rejected by the other commissioners.) By doing so, load serving entities (LSEs) will be left to hedging their own portfolios on their own basis. That will lead to LSEs signing more long term agreements of various kinds.
The alternative of forcing CCAs and ESP to sign fixed price contracts under the current PCIA structure forces them to bear the risk burden of both departed and bundled customers, and the IOUs are able to pass through the risks of their long term agreements through the PCIA.
California would be well service by the DMM to point out this inherent structural problem. We should learn from our previous errors.
This entry was posted in Energy innovation and tagged CAISO, California, CCA, CPUC, electricity rates, M.Cubed, PCIA, PPAs, regulation, renewables, resource adequacy, stranded assets on January 19, 2021 by Richard McCann.
Should CCAs accept a slice of Diablo Canyon power?
The northern California community choice aggregators (CCAs) are considering a offer from PG&E to allocate to each CCA a proportionate share of parts of its portfolio, including the Diablo Canyon nuclear generation station. Many CCA boards are hearing from anti-nuclear activists to deny this offer, both for moral reasons and the belief that such a rejection will somehow pressure PG&E financially. The first set of concern is beyond my professional expertise, but their reasoning on the economic and regulatory issues is incorrect.
CCAs buy a substantial portion of their generation (the majority for many of them) from the California Independent System Operator (CAISO) energy markets. PG&E schedules Diablo Canyon into those CAISO markets and under the current CAISO tariffs, nuclear generation is a "must take" resource that the CAISO can't turn back. So the entire output of Diablo Canyon is scheduled into the CAISO market (without any bidding process), PG&E is paid the market clearing price (MCP) for that Diablo power, and the CCAs buy that mix of nuclear power at the MCP. There is no discretion for either the CAISO or the CCAs in taking excess power from Diablo. There is no "lifeline" for Diablo that the CCAs have any control over under current legal and regulatory parameters.
CCAs already pay for a proportionate share of Diablo Canyon equal to the CCAs share of overall load. That payment is broken into two parts (and maybe a third): 1) the purchase of energy from the CAISO at the MCP and 2) the stranded capital and operating costs above the MCP in the PCIA. (CCAs also may be paying for a share of the resource adequacy, but I haven't thought through that one.) Thus, if the CCAs receive credit for the energy that they are already paying for, the energy portion essentially comes as "free". In addition, because CCAs currently pay for the remaining share of Diablo costs, but get no energy credit for that in the PCIA calculation, then that credit is in the PCIA is also "free". In addition, the CCAs gain credit for Diablo's GHG-free generation (as recognized in the Air Resources Board GHG allowance program) as LSE's for no extra cost, or for "free." The bottom line is when the CCAs gain credit for products that they are already paying for, receipt of those products is for "free."
Accepting this deal will not solve ALL of the CCAs problems, but that's a false goal. That was never the intent. It does however give the CCAs a respite to get through the period until Diablo retires. One needs to recognize that this provides some of the needed relief.
Finally, there's never any certainty over any large deal. Uncertainty should not freeze decision making. The uncertainty about the PCIA going forward is equally large and perhaps offsetting. The risks should be identified, discussed, considered and addressed to the extent possible. But that's different than simply nixing the deal without addressing the other large risk. Naively believing that Diablo can be closed in short order (especially with the COVID crisis) is not a true risk management strategy.
From these points, we can come to these conclusions:
Whether the CCAs accept or reject the nuclear offer has NO impact on PG&E's revenue stream. The decisions that the CCAs face are entirely about whether the CCAs can lower their costs and gain some additional GHG reduction credits that they are already paying for (in other words, reduce their subsidies of bundled customers.) Nothing that the CCAs decide will affect the closure date of Diablo. If the CCAs reject the allocations, it will simply be business as usual to the full closures in 2025. Any other interpretation doesn't reflect the current regulatory environment at the CPUC which are unlikely to change (and even that is unknown) until enough commissioners' five-year terms roll over.
The system can only be changed by legislative and regulatory action. That means that the CCAs must make the most prudent financial decisions within the current context rather than making a purely symbolic gesture that is financially adverse and will do nothing to change the BAU practice. A wise decision would consider what is the true impact of the action on
Finally, early closure of Diablo will NOT remove the invested capital cost from PG&E's ratebase, which is what drives the PCIA. After the plant is closed, activists will ALSO have to show that the INVESTMENT in the plant was imprudent and should not have been allowed. Given the long history on decisions and settlements in Diablo investment costs and the inclusion of recovery of Diablo costs in both AB1890 and AB1X at the beginning and end of the energy crisis, that is an impossible task. Only a constitutional amendment through the initiative process could possibly lead to such an action, and even that would have to survive a court challenge that probably would push past 2024.
I want to finish with what I think is a very important point that has been overlooked by the activists: The effort to close Diablo Canyon has won. Activists might not like the timeline of that victory, but it is a victory nevertheless that looked unachievable prior to 2016. It's worthwhile considering whether the added effort for what will be for a variety of reasons little gain is an important question to answer.
Note that Diablo Canyon is already scheduled for closure in 2024 and 2025. A proceeding to either reopen A.16-08-006 or to open a new rulemaking or application would probably take close to a year, so the proceeding probably wouldn't open until almost 2021. The actual proceeding would take up to a year, so now we're to 2022 before an actual decision. PG&E would have to take up to a year to plan the closure at that point, which then takes us to 2023. So at best the plant closes a year earlier than currently scheduled. In addition, PG&E still receives the full payments for its investments and there's likely no capital additions avoided by the early closure, so the cost savings would be minimal.
This entry was posted in Energy innovation and tagged CAISO, California, CCA, electricity, GHG, nuclear power, PCIA, PG&E on April 15, 2020 by Richard McCann.
We've already paid for Diablo Canyon
As I wrote last week, PG&E is proposing that a share of Diablo Canyon nuclear plant output be allocated to community choice aggregators (CCAs) as part of the resolution of issues related to the Integrated Resource Plan (IRP), Resource Adequacy (RA) and Power Charge Indifference Adjustment (PCIA) rulemakings. While the allocation makes sense for CCAs, it does not solve the problem that PG&E ratepayers are paying for Diablo Canyon twice.
In reviewing the second proposed settlement on PG&E costs in 1994, we took a detailed look at PG&E's costs and revenues at Diablo. Our analysis revealed a shocking finding.
Diablo Canyon was infamous for increasing in cost by more than ten-fold from the initial investment to coming on line. PG&E and ratepayer groups fought over whether to allow $2.3 billion dollars. The compromise in 1988 was to essentially shift the risk of cost recovery from ratepayers to PG&E through a power purchase agreement modeled on the Interim Standard Offer Number 4 contract offered to qualifying facilities (but suspended as oversubscribed in 1985).
However, the contract terms were so favorable and rich to PG&E, that Diablo costs negatively impacted overall retail rates. These costs were a key contributing factor that caused industrial customers to push for deregulation and restructuring. As an interim solution in 1995 in anticipation of forthcoming restructuring, PG&E and ratepayer groups arrived at a new settlement that moved Diablo Canyon back into PG&E's regulated ratebase, earning the utilities allowed return on capital. PG&E was allowed to keep 100% of profit collected between 1988 and 1995. The subsequent 1996 settlement made some adjustments but arrived at essentially the same result. (See Decision 97-05-088.)
While PG&E had borne the risks for seven years, that was during the plant startup and its earliest years of operation. As we've seen with San Onofre NGS and other nuclear plants, operational reliability is most at risk late in the life of the plant. PG&E's originally took on the risk of recovering its entire investment over the entire life of the plant. The 1995 settlement transferred the risk for recovering costs over the remaining life of the plant back to ratepayers. In addition, PG&E was allowed to roll into rate base the disputed $2.3 billion. This shifted cost recovery back to the standard rate of depreciation over the 40 year life of the NRC license. In other words, PG&E had done an end-run on the original 1988 settlement AND got to keep the excess profits.
The fact that PG&E accelerated its investment recovery over the first seven years and then shifted recovery risk to ratepayers implies that PG&E should be allowed to recover only the amount that it would have earned at a regulated return under the original 1988 settlement. This is equal to the discounted net present value of the net income earned by Diablo Canyon, over both the periods of the 1988 (PPA) and 1995 settlements.
In 1996, we calculated what PG&E should be allowed to recover in the settlement given this premise. We assumed that PG&E would be allowed to recover the disputed $2.3 billion because it had taken on that risk in 1988, but the net income stream should be discounted at the historic allowed rate of return over the seven year period. Based on these assumptions, PG&E had recovered its entire $7.7 billion investment by October 1997, just prior to the opening of the restructured market in March 1998. In other words, PG&E shareholders were already made whole by 1998 as the cost recovery for Diablo was shifted back to ratepayers. Instead the settlement agreement has caused ratepayers to pay twice for Diablo Canyon.
PG&E has made annual capital additions to continue operation at Diablo Canyon since then and a regulated return is allowed under the regulatory compact. Nevertheless, the correct method for analyzing the potential loss to PG&E shareholders from closing Diablo is to first subtract $5.1 billion from the plant in service, reducing the current ratebase to capital additions incurred since 1998. This would reduces the sunk costs that are to be recovered in rates from $31 to $3 per megawatt-hour.
Note that PG&E shareholders and bondholders have earned a weighted return of approximately 10% annually on this $5.1 billion since 1998. The compounded present value of that excess return was $18.1 billion by 2014 earned by PG&E.
This entry was posted in Energy innovation and tagged California, CCA, CPUC, Diablo Canyon, electricity, electricity rates, M.Cubed, nuclear power, PCIA, PG&E on February 11, 2020 by Richard McCann.
CCAs don't undermine their mission by taking a share of Diablo Canyon
Northern California community choice aggregators (CCAs) are considering whether to accept an offer from PG&E to allocate a proportionate share of its "large carbon-free" generation as a credit against the power charge indifference adjustment (PCIA) exit fee. The allocation would include a share of Diablo Canyon power. The allocation for 2019 and 2020; an extension of this allocation is being discussed on the PCIA rulemaking.
The proposal faces opposition from anti-nuclear and local community activists who point to the policy adopted by many CCAs not to accept any nuclear power in their portfolios. However, this opposition is misguided for several reasons, some of which are discussed in this East Bay Community Energy staff report.
The CCAs already receive and pay for nuclear generation as part of the mix of "unspecified" power that the CCAs buy through the California Independent System Operator (CAISO). The entire cost of Diablo Canyon is included in the Total Portfolio Cost used to calculate the PCIA. The CCAs receive a "market value" credit against this generation, but the excess cost of recovering the investment in Diablo Canyon (for which PG&E is receiving double payment based on calculations I made in 1996) is recovered through the PCIA. The CCAs can either continue to pay for Diablo through the PCIA without receiving any direct benefits, or they can at least gain some benefits and potentially lower their overall costs. (CCAs need to be looking at their TOTAL generation costs, not just their individual portfolio, when resource planning.)
Diablo Canyon is already scheduled to close Unit 1 in 2024 and Unit 2 in 2025 after a contentious proceeding. This allocation is unlikely to change this decision as PG&E has said that the relicensed plant would cost in excess of $100 per megawatt-hour, well in excess of its going market value. I have written extensively here about how costly nuclear power has been and has yet to show that it can reduce those costs. Unless the situation changes significantly, Diablo Canyon will close then.
Given that Diablo is already scheduled for closure, the California Public Utilities Commission (CPUC) is unlikely to revisit this decision. But even so, a decision to either reopen A.16-08-006 or to open a new rulemaking or application would probably take close to a year, so the proceeding probably would not open until almost 2021. The actual proceeding would take up to a year, so now we are to 2022 before an actual decision. PG&E would have to take up to a year to plan the closure at that point, which then takes us to 2023. So at best the plant closes a year earlier than currently scheduled. In addition, PG&E still receives the full payments for its investments and there is likely no capital additions avoided by the early closure, so the cost savings would be minimal.
This entry was posted in Energy innovation and tagged California, CCA, Diablo Canyon, GHG, greenhouse gases, nuclear power, PCIA, PG&E, PG&E electricity rates, renewables on January 28, 2020 by Richard McCann.
Exit fee market benchmarks threaten CCAs abilities to meet long term obligations
CCAs may have to choose between complying with the long-term commitments specified in Senate Bill 350 and continuing to operate because they cannot acquire resources at the specified market price benchmarks that value the entire utility portfolio according to the CPUC.
The chart above compares the revenue shortfalls that need to be made up from other capacity sales products to finance resource additions. The CAISO has reported for every year since 2001 that its short-run market clearing prices that were adopted as the market price benchmark in the PCIA have been insufficient to support new conventional generation investment. The chart above shows the results of the CAISO Annual Report on Market Issues and Performance compiled from 2012 to 2018, separated by north (NP15 RRQ) and south (SP15 RRQ) revenue requirements for new resources. (The historic data shows that CAISO revenues have never been sufficient to finance a resource addition.) The CAISO signs capacity procurement (CPM) agreements to meet near-term reliability shortfalls which is one revenue source for a limited number of generators. The other short run price is the resource adequacy credits transacted by load serving entities (LSE) such as the utilities and CCAs. This revenue source is available to a broader set of resources. However, neither of revenues come close to closing the cost shortfall for new capacity.
The CPUC and the CAISO have deliberately suppressed these market prices to avoid the price spikes and reliability problems that occurred during the 2000-2001 energy crisis. By explicit state policy, these market prices are not to be used for assessing resource acquisition benchmarks. Yet, the CPUC adopted in its PCIA OIR decision (D.18-10-019) exactly this stance by asserting that the CCAs must be able to acquire new resources at less than these prices to beat the benchmarks used to calculate the PCIA. The CPUC used the CAISO energy prices plus the average RA prices as the base for the market value benchmark that represents the CCA threshold.
In a functioning market, the relevant market prices should indicate the relative supply-demand balance–if supply is short then prices should rise sufficiently to cover the cost of new entrants. Based on the relative price balance in the chart, no new capacity resources should be needed for some time.
Yet the CPUC recently issued a decision (D.19-04-040) that ordered procurement of 2,000 MW of capacity for resource adequacy. And now the CPUC proposes to up that target to 4,000 MW by 2021. All of this runs counter to the price signals that CPUC claims represent the "market value" of the assets held by the utilities.
If the CCAs purchase resources that cost more than the PCIA benchmarks then they will be losing money for their ratepayers (note that CCAs have no shareholders). Most often long-term power purchase agreements (PPA) have prices above the short-term prices because those short-term prices do not cover all of the values transacted in the market place. (More on that in the near future.) The CPUC should either align its market value benchmarks with its resource acquisition directives or acknowledge that their directives are incorrect.
This entry was posted in Energy innovation and tagged California, CCA, community choice aggregation, CPUC, electricity rates, exit fee, market price benchmark, PCIA, PG&E, SCE, SDG&E on November 4, 2019 by Richard McCann.
PG&E has cost California over $3 billion by mismanaging its RPS portfolio
When community choice aggregators take up serving PG&E customers, PG&E saves the cost of having to procure power for the departed load. Instead the CCAs bear that cost for that power. The savings to PG&E's bundled customers are not fully reflected when calculating the exit fee (known as the power charge indifference adjustment or PCIA) for those CCAs. As a result, the exit fee does not reflect the true value that CCAs provide to PG&E and its bundled customers.
The chart above shows the realized and potential savings to PG&E from the departure of CCA customers. The realized part is the avoided costs of procuring resources to meet that load, shown in yellow. The second part is the foregone sales opportunity if PG&E had sold a portion of its portfolio to the CCAs at the going price when they departed. In 2019, these combined savings could have reached $3.2 billion if PG&E had acted prudently.
Many local governments launched CCAs to address their climate goals, and CCAs issued multiple requests for offers of RPS energy. However, PG&E failed to respond to this opportunity to sell excess renewable energy no longer needed to serve their customers. By deciding to hold these unneeded resources in a declining market, PG&E accumulated additional losses every year. Indeed, the assigned Judge on the exit-fee proceeding at the CPUC concluded that PG&E must benefit from "holding back the RECs [renewable energy credits] for some reason."
This willingness to hold onto an unneeded resource that loses value every year is contrary to prudent management. However, shareholders, are shielded entirely from contract that are too costly, and only pay penalties for failing to meet RPS targets. Instead, ratepayers—both bundled and CCA—pay all of the excessive costs, and shareholders only have a strong incentive to over-procure using those ratepayer dollars to avoid any possibility of reduced shareholder profits. Holding these contracts also inflates the exit-fee departed customers must pay, making it harder for alternatives like public power and distributed generation to PG&E to thrive.
When Sonoma Clean Power launched in 2014, the average price of RPS energy was $128/MWh. It has declined every year, and now sits at $57/MWh. PG&E's decision to not sell excess energy at 2014 prices, and to protect shareholders at the expense of ratepayers has cost customers over $3 billion dollars in the last 6 years as shown in the green columns below. As RPS prices continue to decline, and the amount of customer departing increases, this figure will continue to increase every year. Indeed, it surpassed $1.1 billion for 2019 alone.
Further, the hedging value of the RPS resources that PG&E listed as key attribute of holding these PPAs instead of disposing of them has diminished dramatically since PG&E pushed that as its strategy in its 2014 Bundled Procurement Plan. As shown in the chart above, the hedge value fell $1.3 billion from 2014 to 2019, from a high of $961 million to a burden of $343 million. PG&E's hedge now adds $33/MWH to the cost of its renewables portfolio.
In comparison, Southern California Edison's renewables portfolio costs just under $20/MWH less than PG&E's. SCE did not rush into signing PPAs like PG&E and did not sign them for as long of terms as PG&E.
This entry was posted in Energy innovation and tagged California, CCA, community choice aggregation, electricity rates, exit fee, PCIA, PG&E, renewables, RPS, SCE on October 28, 2019 by Richard McCann.
PG&E "buys dear, sells cheap"
PG&E spends $275 million a year on energy efficiency investments that reduce demand by 100 MW. It also spends $65 million a year on demand response to reduce peak loads by 400 MW. If we assume that energy efficiency investments are effective an average of 12 years the incremental cost of those investments is $66 per MWH (6.6 cents per kWh). For demand response the incremental cost, which should match the market value, is $163 per kilowatt-year (or $13.60 per kW-month). Both of these values are reasonable investments for long-term resources.
Yet, PG&E argues in the PCIA exit fee proceeding and its annual ERRA generation cost proceeding that the appropriate market valuation for its resources are the short-term fire sale values that it realizes in the daily markets. According to PG&E, customers do not realize any additional value from holding these resources beyond what those resources can be bought and sold for the CAISO markets and in bilateral short-term deals.
So we are left with the obvious question: Why is PG&E continuing to invest in energy efficiency and demand response if the utility states that it can meet all of its needs in the short-term markets? This hypocrisy is probably best explained by PG&E manipulating the regulatory process. PG&E's proposed "market valuation" sets the exit fee for community choice aggregation (CCA) at a high level. Instead, that market valuation should reflect how much CCAs have saved bundled customers in avoided procurement, and what PG&E pays for adding new resources.
This entry was posted in Energy innovation and tagged California, CCA, electricity, energy economics, energy efficiency, PCIA, PG&E on December 13, 2018 by Richard McCann.

redpajama_set_name: RedPajamaCommonCrawl


text:
now reading: Coastal California Shouldn't Ignore CA's 'Flyover' Area
Coastal California Shouldn't Ignore CA's 'Flyover' Area
By Carson Bruno
With Donald Trump's surprising Electoral College victory - 306 to 232 as of November 16 - a lot of focus has been on the angst and anger of voters in so-called "fly over" portions of the country. Regardless of your opinions of now President-elect Trump or former Secretary of State Hillary Clinton, the 2016 Presidential election gave voice to a sizable class of voters who feel either betrayed or forgotten about by our elected leaders.
But sticking out like a sore thumb on the Electoral College map is California. As of November 16, Clinton's strongest state victory is the Golden State. Moreover, Clinton's California margin of victory is the best Democratic Presidential nominee performance since President Franklin Roosevelt's 1936 re-election against then-Kansas Governor Alf Landon. And while she may not reach FDR's whooping 35-point victory, with 4.1 million votes still left to be counted in California, Clinton will definitely pad her 29-point victory in the same state that launched both President Nixon and President Reagan's political careers.
It is no wonder, then, that California Assembly Speaker Anthony Rendon and Senate President Pro Tem Kevin De León issued a joint statement following the November 8 election results saying they "woke up feeling like strangers in a foreign land" and that Americans voted in a manner "clearly inconsistent with the values of the people of California."
While California clearly did reject the political tone and policies of Donald Trump - for instance, Orange County was one of the few counties nationwide to flip from supporting Mitt Romney in 2012 to support Clinton this election year - it may be unwise for California's political leaders, who as Democrats dominate the Golden State's one-party rule, to blithely ignore the clear message many in the country sent to Washington, D.C. - they feel left behind and ignored.
Viewing the inland California (i.e. California's version of "fly over" country) versus coastal California divide forewarns of a possible revolt against the elites here in California if Democratic one-party rule isn't careful and California Republicans can rehabilitate their image.
The Have's and the Have-Not's: Of the coastal California counties, the average unemployment as of September 2016 was 4.8 percent. Moving inland, the average unemployment rate was about 1.5 times higher at 7.4 percent. Even this hides the disparity between the regions. The state's healthiest job environment is in toney Marin County (3.5 percent), while California's worst job environment is in the heavily Latino and heavily immigrant Imperial County (23.7 percent). Moreover, coastal California has boomed out of the recession, while inland California is still limping out of it. Average 10 year GDP growth for coastal California has been almost 2 percent per year versus just 0.6 percent per year for their inland neighbors. And these realities directly impact Californians pocketbooks. Based on Tax Year 2013 data, the average adjusted gross income for those living in coastal California is almost 2 times higher than those inland - $33,176 compared to $18,613.
A Not-So-Welcome to (Coastal) California: The above might not be such a detrimental issue for many if there were barrier-less ways to move from inland California to the coastal communities; but that is far from the case - the barriers are indeed quite high. First, coastal housing prices are at 91% of their pre-recession peak averaging just over $677,000. This is in stark comparison to inland California where housing prices are still a quarter below pre-recession levels averaging just under $300,000 - more than half the cost of coastal California. But even renting - long considered the "affordable" option - isn't actually an option for most: coastal rents are almost twice the level of inland rents. But even if an individual or family bites the bullet and absorbs the higher cost of living into their budgets, they soon will realize that all goods and services are more expensive in coastal California. There is about a 15 percent premium on goods and services in coastal California compared to the national average. For inland California, it's a 2 percent discount relative the nation as a whole.
At the end of the day, coastal Californians not only have more job opportunities, but those opportunities pay more. And they are sheltered from others since the barriers to entry are high and tenuous. The more California policy reflects the wants and wishes of coastal California, the more likely those living inland will feel left behind or ignored. And 2016 showed that when public policy forgets about the public, unpredictable events can occur.
Carson Bruno is the assistant dean for admission and program relations at the Pepperdine School of Public Policy. Follow him on Twitter @CarsonJFBruno.
Related Topics: California
Log In with your RCMG Account Register


text:
Episode 137 - Winston S.
Digital Original Stephanie Hollman Says This Is the Worst Part About Being a Real Housewife
Digital Original This Is LeeAnne Locken's Favorite Thing About Being a Texan
Preview Whitney Sudler-Smith Refuses to Admit That He Hooked Up With Kathryn Dennis
Preview Your First Look at The Real Housewives of Dallas Season 4
Digital Original Hannah Ferrier Reacts to Fans' Strangest Google Searches About Her
After Show After Show: What Dorit Kemsley Would Say to Lisa Vanderpump
Show Highlight Ramona Singer & Andy Cohen's Recent Encounter
Show Highlight Dorit Kemsley & Ramona Singer Swap Housewives Scenarios
Show Highlight Ramona Singer is 'Kinda Over' 'Feelin' Jovani'
Last Name Changes After Divorce: What Do Most Women Do?
Why Carole Radziwill and Bethenny Frankel Aren't Close
Anastasia Reflects on Chef Mila: "I Felt For Her But..."
Gretchen Rossi Shares First Photos of Her Baby Girl
What Did Meghan Markle Just Confide in Pharrell Williams?
Carlton Gebbia
@CarltonGebbia13
Carlton Gebbia grew up in London and South Africa before moving to Los Angeles to pursue acting. She is passionate, unconventional, and has a love for animals and nature. Carlton works closely with her husband, David Gebbia, who runs the family businesses alongside his father and two brothers. The businesses include StockCross Financial Services, Rival Sports Group, managing NBA and NFL players, and Gebbia Custom Estates, a developer building high-end custom homes in Beverly Hills and Hidden Hills where Carlton is the interior architectural designer. Carlton takes great pride in having designed their Gothic-inspired home where they currently reside in Beverly Hills. Carlton will say her greatest accomplishments are her three children, Destiny (11), Mysteri (10), and Cross (2) with her husband, David, whom she describes as "truly her soul-mate." She is currently developing a children's book with an unusual twist, writing a horror script, and working with Wildlife Waystation, a Los Angeles non-profit Sanctuary that raises money for exotic and wild animals.
Captain Mark Howard
@CaptMarkHoward_
Captain – Born and raised on a lake in Michigan, Captain Mark Howard has been a yacht captain for almost 30 years, with international experience ranging from sailing the South Pacific to the Mediterranean and Caribbean on both private and charter boats. Mark also has his pilot license and enjoys flying helicopters as a hobby. While he is always approachable and supportive of his crew, Mark demands professionalism and finds it important to be hands-on in all aspects of the yacht's operation. His advice to aspiring yachties is to be honest, work hard, and pay attention to senior crew members while never forgetting the golden rule of yachting: "The guest is always right."
Aviva Drescher
@avivadrescher
Aviva Drescher is the first and only New York City born and bred "Housewife" in the history of the show. At 5'10" with brains to match her beauty, this philanthropist, author, businesswoman, and full-time mother will let nothing hold her back. When Aviva was just six years old, she was in a tragic farm accident that resulted in the amputation of her left leg. Aviva has never let this tragedy define who she is. Aviva has an impressive education that includes a Bachelors of Arts degree from Vassar College, a Masters degree in French from New York University, and a JD from The Benjamin N. Cardozo School of Law. In place of practicing law, she devotes her time to her investment banker husband, Reid, and raising their four children on the Upper West Side. Aviva teaches her family the importance of giving back by example through her philanthropic work as the National Spokesperson for One Step Ahead and CAF organizations helping amputees, as well as by serving as an Advisory Board Member of Cancer Schmancer/Trash Cancer and for her work with the Live4Life Foundation. Aviva's memoire, Leggy Blonde, is out February 25, 2014 and her all natural anti-anxiety supplement, "Tranquil Day," is out in March 2014.
Eliza Limehouse
Eliza Limehouse has family roots in Charleston as old as the city itself. As a ninth generation native, Eliza happily attended galas and charity events around town growing up, mixing and mingling with other socialites. After graduating a year early from Clemson, she returned to Charleston to work in her family business, Limehouse Properties, by managing and renovating the Charleston hotels in their portfolio. Not one to limit herself to one business venture, she also founded a local jewelry line, Snaffle Bit Bracelet Company, which she began in high school. With her business partner Allston Pate, Eliza co-founded Plantation Candle Company and is ambitiously looking to launch an additional fine jewelry, e-commerce line at elizalimehouse.com. When she's not keeping busy in the office, Eliza is also signed with TouT Models and appears in regional campaigns and fashion shows.
Eliza is a passionate advocate for animals. She grew up riding horses on her family plantation Airy Hall, leading her to become a polo player, and taking care of her family dogs and other pets. She has worked with her mother since a young age to rescue and foster as many dogs and horses as she is able. For her future, Eliza wants to own her own farm where she can continue to rescue animals and hopes to become a politician to bring awareness to animal rights issues that she wants changed.
@charrissejordan
A dedicated mother of two teenagers — Jackson, 18 and Skylar, 16 — Charrisse has a reputation that precedes her in the elite Potomac social circle. Maintaining an extensive network both inside and outside of Potomac, Charrisse prides herself on being a dependable friend and confidant. When her packed schedule allows, she loves to shop, socialize, and travel. Well known to throw extravagant parties and events, Charrisse is the ultimate social butterfly who connects the Who's Who of the DC area. Her passion is giving back and she has proudly raised millions for charity based organizations.
Charrisse has been married to NBA player-turned-coach Eddie Jordan for 19 years. The past few years have been challenging living separate as Charrisse worked diligently to keep her family unit together. The past year took a turn and Charrisse had to face the demise of her marriage. Eddie currently resides in New Jersey while Charrisse and the children live in Potomac. Charrisse tackles any obstacle that comes her way with dignity and grace. Her number one priority has always been and will always be her children, as she is determined to be there for them 150% . . . no nannies, period.
Tiffany Copeland
@nautiyachty
Stewardess – Originally from Florida, Tiffany has a background in science and originally began her career as a marine biologist before she discovered her love for yachting. With ambitions of becoming a captain one day, Tiffany is laser focused on learning all of the inner workings of yachting. She has a natural curiosity and finds herself regularly rolling up her sleeves to help the team resolve issues that arise on board. From learning how a boat operates to understanding the responsibilities of each crew member, she aspires to know it all in an effort to prepare for the next step in her career.
@YolandaHFoster
Yolanda was born and raised in Papendrecht, a small farmer's town in Holland where she rode horses, milked cows and loved the farm. She grew up rather fast after her father passed away when she was just seven years old and, feeling the need to provide for her brother and her single mom, she became a dishwasher at the local Chinese restaurant at the age of 13. At age 16, she was discovered by world-famous modeling agent, Eileen Ford, and left Holland to become an international model living and working in Paris, Milan, Hamburg, Sydney, Tokyo, and eventually New York City. In 1994 she moved to Los Angeles and started her family with former husband, Mohamed Hadid, with whom she has 3 children, Gigi, Bella and Anwar. On the mystical day of 11-11-11, Yolanda married the love of her life, producer, songwriter, and 16-time Grammy Award-winner, David Foster. Yolanda juggles a blended family of her own children plus five stepdaughters.
@KyleRichards
Kyle Richards, a California native, was born into an acting family in Hollywood, California. She landed her first role at age four in Disney's Escape to Witch Mountain, where she played the younger version of her sister, Kim Richards. Kyle's television credits include Little House on the Prairie, Carter Country, Down To Earth, E.R., and NBC's Celebrity Apprentice. Her film credits include Halloween and The Watcher in the Woods. Additional acting credits include Deadly Sibling Rivalry, and a guest appearance on CSI and Days of Our Lives. Her husband, Mauricio Umansky, is one of the nation's top realtors, and founder and CEO of The Agency, a real estate company representing clients around the world. Kyle is currently developing new television series, running her high-end boutiques, and looking for a new space for her retail store Kyle by Alene Too. Kyle's greatest passion, however, is being a mother to her four daughters: Farrah, Alexia, Sophia and Portia.


The benefits: The people in our business are passionate about what they do everyday, helping people get into to work and thrive. Coming to work every day to work with a positive team, while you support others in their job search, is something that would be hard to find anywhere else. For your passion and hard work you are rewarded with a competitive base salary and team bonuses.


text:
The Wellington and Manawatu Railway Company (WMR or W&MR) was a private railway company that built, owned and operated the Wellington-Manawatu railway line between Thorndon in Wellington, the capital of New Zealand, and Longburn, near Palmerston North in the Manawatu, between 1881 and 1908, when it was acquired by the New Zealand Government Railways. Its successful operation in private ownership was unusual for early railways in New Zealand.

History
At the time of the company's founding in 1881, the government had built the Foxton Branch railway linking Palmerston North and Foxton, and had completed surveys of lines down the west coast to Wellington. The government of Sir George Grey had approved the construction of the line, which was included in the Public Works Estimates of 27 August 1878. The final details of the survey were completed, and the first workers for the construction of the line were hired on 21 August 1879. A short section of the line, from Wellington to Wadestown, was partially constructed. However, Grey's government was defeated at the September 1879 general election and left office in October 1879. The government of Sir John Hall took office and he had the line removed from the Public Works Estimates. Hall then created a Royal Commission to review the government's public works programme, with a view to reducing government expenditure. The Commission reviewed the Wellington-Manawatu line in March 1880, and concluded that work should be abandoned.

Company formation
Backed by the Wellington Chamber of Commerce, a group of prominent Wellington businessmen decided to form a company to fund the railway's construction. They did so on 15 February 1881, issuing 100,000 shares at £5 each. By May 1881 43,000 shares had been sold, including a substantial package to Māori landowners in the Manawatu, who exchanged land along the proposed route for shares in the company.

In May 1881 the company signed a contract with the government to purchase the land, formation and materials used for building the line so far (which had already cost £30,000). The government made certain undertakings limiting the company's profitability and dividend payments, and made substantial grants of Crown land (210,500 acres or 85,186 hectares) to prevent land speculation and make the railway a viable entity. The total land grants were valued at £96,000.00. The contract stipulated the line was to be built within five years of commencement; it took four years and two months to build.  The contract also included a clause for the government to purchase the company in the future at a "fair value", something that was later to prove contentious.

The government had proposed that the new "West Coast" line would go via Foxton, but the new company (William Travers) said in February 1881 that the route would to follow the most direct route to Palmerston North (via Fitzherbert, connecting with the NZR at Longburn), so bypassing Foxton. This was a shorter and more direct route to Napier and Auckland (72 not 82 miles), and avoided "unproductive country" in favour of a route with potentially better hinterland. As the company was raising money by selling shares, William Fox said that the terminus had not yet been decided and that Travers was not authorised to make an announcement, and consideration of engineering difficulties and cost would be required (although the company directors would then choose the shorter route!).

In August 1881 the Railways Construction and Land Act was passed, allowing joint-stock companies to build and run private railways, as long as they were built to the government's standard rail gauge of  and connected with the government railway lines. The Act had the effect of authorising the WMR (and also the New Zealand Midland Railway Company).

Construction of the line recommenced on 25 September 1882. Construction was completed on 27 October 1886, with the first through train running on 3 November; see Wellington–Manawatu Line

Operations
The WMR was relatively successful and generated considerable revenue. Its land holdings proved to be a major revenue stream for the company; as sections of the lines opened, the land value around it increased and thus the WMR profited from its own operations. The new line opened up 5 million acres (2 million ha), and as the line length was 84.5 miles the company was entitled to £126,375 of land. The government allocated £96,570 of land within a 15-mile radius from the line and agreed to allocate £29,805 more of land from land acquired in the next five years. But while the company got Maori owners to agree to sell the Horowhenua Block the government did not act within five years, and ignored petitions to parliament. So the government offered in settlement only £5339 worth of land in 1894, knowing the company could not afford a lawsuit. The company had paid the government and local bodies £118,550, amounting to two-thirds of its paid-up capital and 20% more than the total value of the land grants. The cost of the railway and equipment to February 1905 was £1,010,197 with land grants amounting to £98,644. Since the grants were made,  the value of the land had appreciated by £6,369,837. And land sales raised money to complete the railway.

The railway's operations were advanced by standards of the time, having comfortable carriages, dining cars, electric lighting, and telephone communication between stations. By comparison, the government-operated network did not introduce dining cars until 1902. From 1895 the 53 lb/yard (26 kg/metre) rails on the Wellington-Plimmerton-Paekakariki section were replaced with 65 lb/yard (32 kg/metre) rails.  In 1900–02 the rolling stock was fitted with Westinghouse air brakes.

Dissolution
The WMR was bought by the government in 1908 (as soon as it could be purchased without penalty), and was integrated into the New Zealand Railways Department from Monday 7 December 1908. The staff, 123 in 1886–87, grew to 382 by 1908, of whom 324 transferred to the NZR. The NZR also took over 20 locomotives, 56 bogie passenger cars, 14 brake vans, 343 wagons and two 10-ton hand cranes.

The company had paid a 6% or 7% annual dividend, a return averaging 13½% per year, and when the company was taken over shareholders got 55 to 60 shillings a share. Of the 633 shareholders on the Wellington register, 307 were "originals".

The line

The WMR line ran for about . From the Thorndon terminus it wound up through the hills to Johnsonville, now the Johnsonville Branch. It then proceeded to Tawa, roughly along the line of the State Highway 1 motorway. This section was bypassed by the Tawa Flat deviation from 19 June 1937. From Tawa to Longburn the North Island Main Trunk line generally follows its route, through Porirua, Paekakariki, Paraparaumu, Otaki, and Shannon. The decision to pass through Shannon meant that the line joined the Foxton Branch in the middle, terminating at Longburn, rather than at Foxton — the routing was strongly debated, and was chosen as being more direct. A number of new towns were established along the route, notably Plimmerton, named after company director and "Father of Wellington" John Plimmer. Levin, named after William Hort Levin, and Shannon, named after George Vance Shannon (1842–1920), were also named after directors of the company.

The WMR used simple unprepossessing stations, stating in 1893 that it does not build stations for future generations of travellers as our Government seems to – but adapts expenditure to actual requirements leaving additions to be made as wanted.

Wellington (Thorndon) and Longburn station buildings were provisional, as the government procrastinated in building joint stations (and as it was suggested that WMR trains could run to Palmerston North over the NZR line, at a cost. WMR passenger trains eventually ran to Palmerston North Central railway station.)
Other stations were based on PWD designs for 4th, 5th & 6th class stations, They all had a central waiting area open at the front with seating along the rear and one side, and a simple sloped roof dropping to the rear but no verandah. The 4th & 5th class stations had an office with ticket slide at one end and a ladies' waiting room at the other end, while the 6th class or Flag stations only had an office:
Fourth Class (42 ft x 14 ft): Johnsonville, Paremata, Otaki, Shannon.
Fifth Class (34 ft 8 in x 14 ft 9 in): Crofton, Khandallah, Porirua, Plimmerton, Paekakariki.
Sixth Class (Flag) (about 15 ft x 8 ft): Tawa Flat, Plimmerton, Pukerua, Paraparaumu, Waikanae, Te Horo, Hadfield, Manukau, Ohau, Levin (original), Kereru, Makerua, Tokomaru, Linton.

Motive power
The WMR operated 22 locomotives in revenue service, of which 20 were acquired by the government (the original Nos. 3 & 5 were sold to the Timaru Harbour Board).  The WMR classified its locomotives by number without class distinction; if a locomotive was withdrawn its number was re-used on a new locomotive.  When the WMR was acquired by the government, some locomotives joined existing classes (N and V), while others had new class designations established for them. These classes contained few locomotives, so all were withdrawn by 1931 during the 1925–35 standardisation programme. Seven engines were Vauclain compounds from Baldwin. WMR No. 13, built in 1894, was the first compound in New Zealand and the first narrow-gauge compound in the world.

No. 10 became particularly famous when, on 20 July 1892, it achieved 64.4 mph (103.6 km/h) hauling a test train along the level stretch of line between Levin and Shannon, at the time the world speed record for the  gauge.  The locomotive was withdrawn in 1928 and dumped in the Waimakariri River to help stabilise the riverbank, and its final resting place is a mystery.

No. 3 or Jumbo (WJ class) banked north out of Wellington for 25 years (to 1927) on the long and steep 1 in 40 grades up to Crofton (Ngaio) and Khandallah. Other steep grades going north were 1 in 66 between Plimmerton and Pukerua Bay; and going south 1 in 66 from Paekakariki to Pukerua Bay (the North–South Junction) and up to 1 in 54 from Tawa Flat (Tawa) to Johnsonville.

The WMR owned other locomotives for construction and maintenance.  These included a New Zealand Railways Department P class of 1876. Known as Weka, it was used by the WMR from 1882 until 1898, when it was sold to the Manawatu County Council for use on its Sanson Tramway.

Surviving relics

Despite the WMR's short history and its disappearance long before the railway preservation movement began, a number of relics have survived. Of the locomotives, only No. 9 (later NZR N 453) is known to exist, the remains of which were recovered in 2003 by the Wellington and Manawatu Railway Trust. It is under active restoration at Steam Incorporated, Paekakariki. Sister locomotive No. 10 is believed to have been dumped complete along the Midland Line, but has yet to be discovered.  Railway archaeologist Tony Batchelor believes he may have found No. 7 (later NZR V 451) in Southland, but this has yet to be proven.

A number of items of rolling stock survive, including four passenger carriages – 43 ft car No. 35 (NZR A 1113), belonging to MOTAT; 50 ft cars No. 42 (NZR A 1120), stored at the Bush Tramway Club at Rotowaro, and No. 48 (NZR A 1126) and No. 52 (NZR A 1130), both owned by the NZR&LS and stored at the Silver Stream Railway, with No. 48 under active restoration. No bogie wagons are thought to exist, but seven L class 4-wheel wagons survive – one owned by the Wellington and Manawatu Railway Trust, one at the Ferrymead Railway, one in a private collection in Masterton and three owned by SteamRail Wanganui, in poor condition.

The bell at the concourse end of Wellington railway station's platform 6 is believed to be from WMR locomotive no. 17.

Infrastructure remains include the Johnsonville Line, a stone plaque on the eastern abutment of the bridge across Hutt Rd in Wellington, the foundations of the Belmont Viaduct near Johnsonville, most of the NIMT north of Tawa, the railway station at Shannon, the former Te Horo station (now at the Tokomaru Steam Museum) and the Forest Lakes rail bridge. A memorial at Otaihanga on the NIMT commemorates the driving of the WMR's last spike.

See also
Harry Higginson
Arthur Fulton
James Edward Fulton
Wellington-Manawatu Line
50-foot carriages of WMR

References

Citations

Bibliography

External links
Wellington and Manawatu Railway Trust

Last Annual Report of the Wellington & Manawatu Railway Company
Paekakariki Rail & Heritage Museum

Another image from the brochure Country to be opened up by Railway showing a drawing of the Belmont viaduct
b/w pictures of the Belmont viaduct from Alexander Turnbull Library - 1880s, c1890, 1912.
Photo of Wadestown and the Manawatu Line from 1911 paper
1897 article on WMR Co from Cyclopaedia of New Zealand

Rail transport in the Wellington Region
Railway companies of New Zealand
1908 disestablishments in New Zealand
Rail lines receiving land grants
Rail transport in Manawatū-Whanganui
New Zealand companies established in 1881
Railway companies established in 1881
Railway companies disestablished in 1908
Defunct transport companies of New Zealand

redpajama_set_name: RedPajamaWikipedia