Tag Archives: regulation

The PCIA is heading California toward another energy crisis

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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.

PG&E’s bankruptcy—what’s happened and what’s next?

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The wildfires that erupted in Sonoma County the night of October 8, 2017 signaled a manifest change not just limited to how we must manage risks, but even to the finances of our basic utility services. Forest fires had been distant events that, while expanding in size over the last several decades, had not impacted where people lived and worked. Southern California had experienced several large-scale fires, and the Oakland fire in 1991 had raced through a large city, but no one was truly ready for what happened that night, including Pacific Gas and Electric. Which is why the company eventually declared bankruptcy.

PG&E had already been punished for its poor management of its natural gas pipeline system after an explosion killed nine in San Bruno in 2010. The company was convicted in federal court, fined $3 million and placed on supervised probation under a judge.

PG&E also has extensive transmission and distribution network with more than 100,000 miles of wires. Over a quarter of that network runs through areas with significant wildfire risk. PG&E already had been charged with starting several forest fires, including the Butte fire in 2015, and its vegetation management program had been called out as inadequate by the California Public Utilities Commission (CPUC) since the 1990s. The  CPUC caught PG&E diverting $495 million from maintenance spending to shareholders from 1992 to 1997; PG&E was fined $29 million. Meanwhile, two other utilities, Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E) had instituted several management strategies to mitigate wildfire risk (not entirely successful), including turning off “line reclosers” during high winds to avoid short circuits on broken lines that can spark fires. PG&E resisted such steps.

On that October night, when 12 fires erupted, PG&E’s equipment contributed to starting 11 of those, and indirectly at least to other. Over 100,000 acres burned, destroying almost 9,000 buildings and killing 44 people. It was the most destructive fire in history, costing over $14 billion.

But PG&E’s problems were not over. The next year in November 2018, an even bigger fire in Butte County, the Camp fire, caused by a failure of a PG&E transmission line. That one burned over 150,000 acres, killing 85, destroying the community of Paradise and costing $16 billion plus. PG&E now faced legal liabilities of over $30 billion, which exceeds PG&E’s invested capital in its system. PG&E was potentially upside down financially.

The State of California had passed Assembly Bill 1054 that provided a fund of $21 billion to cover excess wildfire costs to utilities (including SCE and SDG&E), but it only covered fires after 2018. The Wine Country and Camp fires were not included, so PG&E faced the question of how to pay for these looming costs. Plus PG&E had an additional problem—federal Judge William Alsup supervising its parole stepped in claiming that these fires were a violation of its parole conditions. The CPUC also launched investigations into PG&E’s safety management and potential restructuring of the firm. PG&E faced legal and regulatory consequences on multiple fronts.

PG&E Corp, the holding company, filed for Chapter 11 bankruptcy on January 14, 2019. PG&E had learned from its 2001 bankruptcy proceeding for its utility company subsidiary that moving its legal and regulatory issues into the federal bankruptcy court gave the company much more control over its fate than being in multiple forums. Bankruptcy law afforded the company the ability to force regulators to increase rates to cover the costs authorized through the bankruptcy. And PG&E suffered no real consequences with the 2001 bankruptcy as share prices returned, and even exceeded, pre-filing levels.

As the case progressed, several proposals, some included in legislative bills, were made to take control of PG&E from its shareholders, through a cooperative, a state-owned utility, or splitting it among municipalities. Governor Gavin Newsom even called on Warren Buffet to buy out PG&E. Several localities, including San Francisco, made separate offers to buy their jurisdictions’ grid. The Governor and CPUC made certain demands of PG&E to restructure its management and board of directors, to which PG&E responded in part. PG&E changed its chief executive officer, and its current CEO, Bill Johnson, will resign on June 30. The Governor holds some leverage because he must certify that PG&E has complied by June 30, 2020 with the requirements of Assembly Bill 1054 that authorizes the wildfire cost relief fund for the utilities.

Meanwhile, PG&E implemented a quick fix to its wildfire risk with “public safety power shutoffs” (PSPS), with its first test in October 2019, which did not fare well. PG&E was accused of being excessive in the number of customers (over 800,000) and duration and failing to coordinate adequately with local governments. A subsequent PSPS event went more smoothly, but still had significant problems. PG&E says that such PSPS events will continue for the next decade until it has sufficiently “hardened” its system to mitigate the fire risk. Such mitigation includes putting power lines underground, changing system configuration and installing “microgrids” that can be isolated and self sufficient for short durations. That program likely will cost tens of billions of dollars, potentially increasing rates as much as 50 percent. One question will be who should pay—all ratepayers or those who are being protected in rural areas?

PG&E negotiated several pieces of a settlement, coming to agreements with hedge-fund investors, debt holders, insurance companies that pay for wildfire losses by residents and businesses, and fire victims. The victims are to be paid with a mix of cash and stock, with a face value of $13.5 billion; the victims are voting on whether to accept this agreement as this article is being written. Local governments will receive $1 billion, and insurance companies $11 billion, for a total of $24.5 billion in payouts.  PG&E has lined up $20 billion in outside financing to cover these costs. The total package is expected to raise $58 billion.

The CPUC voted May 28 to approve PG&E’s bankruptcy plan, along with a proposed fine of $2 billion. PG&E would not be able to recover the costs for the 2017 and 2018 fires from ratepayers under the proposed order. The Governor has signaled that he is likely to also approve PG&E’s plan before the June 30 deadline.

PG&E is still asking for significant rate increases to both underwrite the AB 1054 wildfire protection fund and to implement various wildfire mitigation efforts. PG&E has asked for a $900 million interim rate increase for wildfire management efforts and a settlement agreement in its 2020 general rate case calls for another $575 million annual ongoing increase (with larger amounts to be added in the next three years). These amount to a more than 10 percent increase in rates for the coming year, on top of other rate increases for other investments.

And PG&E still faces various legal difficulties. The utility pleaded guilty to 85 chargesof manslaughter in the Camp fire, making the company a two-time felon. The federal judge overseeing the San Bruno case has repeatedly found PG&E’s vegetation management program wanting over the last two years and is considering remedial actions.

Going forward, PG&E’s rates are likely to rise dramatically over the next five years to finance fixes to its system. Until that effort is effective, PSPS events will be widespread, maybe for a decade. On top of that is that electricity demand has dropped precipitously due to the coronavirus pandemic shelter in place orders, which is likely to translate into higher rates as costs are spread over a smaller amount of usage.

End the fiction of regulatory oversight of California’s generation

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M.Cubed is the only firm willing to sign the non-disclosure agreements (NDA) that allow us to review the investor-owned utilities’ (IOUs) generation portfolio data on behalf of outside intervenors, such as the community choice aggregators (CCAs). Even the direct access (DA) customers who constitute about a quarter of California’s industrial load are represented by a firm that is unwilling to sign the NDAs. This situation places departed load customers, and in fact all customers, at a distinct disadvantage when trying to regulate the actions of the IOUs. It is simply impossible for a single small firm to scrutinize all of the filings and data from the IOUs. (Not to mention that one, SDG&E, gets a complete free pass for now as that it has no CCAs.)

This situation has arisen because the NDAs require that the “reviewing representatives” not be in a position to advise market participants, such as CCAs or energy service providers (ESPs) that sell to DA customers, on procurement decisions. This is an outgrowth of AB 57 in 2002, a state law passed to bring IOUs back into the generation market after the collapse of restructuring in 2001. That law was intended to the balance of power to the IOUs away from generators for procurement purposes. Now it puts the IOUs at a competitive advantage against other load serving entities (LSEs) such as CCAs and ESPs, and even bundled customers.

This imbalance has arisen for several insurmountable reasons:

  • No firm can build its business on serving only to review IOU filings without offering other procurement consulting services to clients.
  • It is difficult to build expertise for reviewing IOU filings without participating in procurement services for other LSEs or resource providers. (I am uniquely situated by the consulting work I did for the CEC on assessing generation technology costs for over a decade.)
  • CPUC staff similarly lacks the expertise for many of the same reasons, and are relatively ineffective at these reviews. The CPUC is further limited by its ability to recruit sufficient qualified staff for a variety of reasons.

If California wants to rein in the misbehavior by IOUs (such as what I’ve documented on past procurement and shareholder returns earlier), then we have two options to address this problem going forward:

  1. Transform at least the power generation management side of the IOUs into publicly owned entities with more transparent management review.
  2. End the annual review and setting of PCIA and CTC rates by establishing one-time prepayment amounts. By prepaying or setting a fixed annual amount, the impact of accounting maneuvers are diminished substantially, and since IOUs can no longer shift portfolio management risks to departed load customers, the IOUs more directly face the competitive pressures that should make them more efficient managers.

Utilities’ returns are too high (Part 2)

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IOU ROE premiums

My previous post, Part 1, showed how California’s utilities’ share prices have risen well above the average across utilities despite claims that investors are risk averse to the California utilities. That valuation premium reflects an excessively high authorized return on equity (ROE) from the California Public Utilities Commission (CPUC).

The utilities’ market values can then be linked to the utilities’ book values and authorized returns on equity to calculate the implied market returns on equity. The authorized income per share is the authorized ROE multiplied by the book value per share. That income is divided by the market share price to arrive at the implied market return on equity for that company. Both Sempra (SRE) and Edison International (EIX) significantly outperform the Dow Jones Utility average and PG&E Corporation (PGC) maintained the same trend until market had significant concerns about the company’s role in the 2017 wildfires.

The figure above tracks the difference or premium value of the authorized ROE over the market valuation of that ROE. A premium value of zero means that the market valuation is on par with the authorized ROE. A higher or positive premium value means that investors see the utility’s equity shares as attractive investments with lower risks than the assessments of the commissions that set the authorized ROEs. In other words, a commission is providing an overly generous incentive to investors if the premium value is positive.  The figure above compares the market implied ROE for the three California holding companies to a market basket of 10 U.S. holding companies that own 17 electric and gas utilities, and do not own significant non-utility subsidiaries. 

At the time of the 2012 cost of capital decision, the authorized ROEs for the California utilities and the basket of U.S. utilities were close to the implied market ROEs. Except for Sempra, which was an outlier as evidenced by its share price growth relative to the other utilities, the authorized ROE was within 100 basis points of the implied market ROE at the end of 2012.  For both Edison International and PG&E Corporation, the authorized ROE and the implied market ROE on December 31, 2012 were exactly on par—10.5% for Edison and 10.4% for PG&E. Only Sempra showed a positive premium of 300 basis points as a result of a rapid increase in market value over 2012.

Over the period from 2012 to late 2017, the implied market ROEprogressed steadily downward–that is, the market value premium increased–for both the California utilities and the other U.S. utilities. Sempra’s premium leveled off in late 2014 and has drifted downward since without any significant corrections. SCE’s diverged upward some from the U.S. utilities mid-2016, but again there are not sharp changes in direction, even with the Thomas Fire in late 2017. PG&E followed the same pattern as SCE until the Wine Country fires in late 2017, and took another sharp turn with the Camp Fire and, understandably, the subsequent voluntary bankruptcy filing.

We can see at the end of September 2017, just after the last Commission decision on cost of capital, the market premium for the 10 utilities had grown to 470 basis points. The premiums for PG&E, Edison and Sempra all lied in a narrow band between 410 basis points for Edison and 470 basis points for PG&E. In other words, 1) California utility investors were receiving overly generous returns on their investments as evidenced in the share prices, and 2) California utility investors have not been demanding a significant discount for perceived increased risk compared to other U.S. utilities, contrary to the assertions by the utilities’ witnesses in this proceeding.

 

Utilities’ returns are too high (Part 1)

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IOU share prices

An analysis of equity market activity indicates that investors have not priced a risk discount into California utility shares, and instead, until the recent wildfires, utility investors have placed a premium value on California utility stocks. This premium value indicates that investors have viewed California as either less risky than other states’ utilities or that California has provided a more lucrative return on investment than other states.

The California Public Utilities Commission (CPUC) should set the authorized return on equity to shareholders (ROE) to deliver an after-tax net income amount as a percentage of the capital invested by the utility or the “book value.” As Alfred Kahn wrote, “the sharp appreciation in the prices of public utility stocks, to one and half and then two times their book values during this period [the 1960s] reflected also a growing recognition that the companies in question were in fact being permitted to earn considerably more than their cost of capital.” (see footnote 69)

The book value is fairly stable and tends to grow over time as higher cost capital is invested to meet growth and to replace older, lower cost equipment. Investors use this forecasted income to determine their valuation of the company’s common stock in market transactions. Generally the accepted valuation is the net present value of the income stream using a discount rate equal to the expected return on that investment. That expected return represents the market-based return on equity or the implied market return.

Alfred Kahn wrote that a commission should generally target the ROE so that the book and market values of the utility company are roughly comparable. In that way, when the utility adds capital, that capital receives a return that closely matches the return investors expect in the market place. If the regulated ROE is low relative to the market ROE, the company will have difficulty raising sufficient capital from the market for needed investments. If the regulated ROE is high relative to the market ROE, ratepayers will pay too much for capital invested and excess economic resources will be diverted into the utility’s costs. On this premise, we compared each of the utilities’ market valuation and implied market ROE against market baskets of U.S. utilities and the current authorized ROEs.

The figure above shows how the stock price for each of the three California utility holding companies (PG&E Corporation (ticker symbol PCG), Edison International (EIX) and Sempra (SRE)) that own the four large California energy utilities. The figure compares these stock prices to the Dow Jones Utility index average from June 1998 to July 2019 starting from a common base index value of 100 on January 1, 2000. The chart also includes (a) important Commission decisions and state laws that have been enacted and are identified by several of the utility witnesses as increasing the legal and regulatory risk environment in the state, and (b) catastrophic events at particular utilities that could affect how investors perceive the risk and management of that utility.

Table 1 summarizes the annual average growth in share prices for the Dow Jones Utility average and the three holding companies up to the 2012 cost of capital decision, the 2017 cost of capital modification decision, and to July 2019. Also of particular note, the chart includes the Commission’s decision on incorporating a risk-based framework into each utility’s General Rate Case process in D.14-12-025. The significance of this decision is that the utility’s consideration of safety risk was directed to be “baked in” to future requests for new capital investment. The updated risk framework also has the impact of making new these new investments more secure from an investment perspective, since there is closer financial monitoring and tracking.

As you can see in both Table 1 and in the figure, the Dow Jones Utility average annual growth was 5.5% through July 13, 2017 and 5.8% through July 18, 2019, California utility prices exceeded this average in all but one case, with Edison’s shares rising 9.4% per annum through the first date and 8.4% through this July, and Sempra growing 15.2% to the first date and even more at 15.3% to the latest. Even PG&E grew at almost twice the index rate at 10.4% in 2017, and then took an expected sharp decline with its bankruptcy.

Table 1

Cumulative Average Growth from January 2000 12/12/2012 7/13/2017 7/18/2019
Dow Jones Utilities 3.9% 5.5% 5.8%
Edison International 7.2% 9.4% 8.4%
PG&E Corp. 8.6% 10.4% 2.4%
Sempra 15.8% 15.2% 15.3%

The chart and table support three important findings:

  • California utility shares have significantly outpaced industry average returns since January 2000 and since March 2009;
  • California share prices only decreased significantly after the wildfire events that have been tied to specific market-perceived negligence on the part of the electric utilities in 2017 and 2018; and
  • Other events and state policy actions do not appear to have a measurable sustained impact on utilities’ valuations.

In Part 2, I show how utilities’ premiums on their authorized ROE have grown over the last decade.

PG&E hijacks its own website

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PG&E PSPS website clip

I was looking for PG&E’s 2019 Catastrophic Events Memo Account (CEMA) on its website at https://www.pge.com/en_US/about-pge/company-information/regulation/regulation.page, and instead I was redirected to PG&E’s PSPS website at https://www.pgealerts.com/. It does not appear possible to get around this website to the regulatory filings that PG&E maintains on its website.

I guess that’s one way to get enough bandwidth after crashing its website during the PSPS blackouts.

PG&E apologizes, yet again

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(Image: ABC 7 News)

I listened to PG&E’s CEO Bill Johnson and his staff apologize for its mishandling of the public safety power shutoffs (PSPS) that affected over 700,000 “customers” (what other industry calls meters “customers”?) yesterday. And as I listened, I thought of the many times that PG&E has fumbled (or even acted maliciously) over the years. Here’s my partial list (and I’m leaving out the faux pas that I’ve experienced in regulatory proceedings):

  • Failing to turn off power locally in 2017 and 2018 under hazardous weather conditions, which led to the Wine Country and Camp fires.
  • Failing to install distribution shut off equipment that was installed by San Diego Gas & Electric and Southern California Edison after the 2007 wildfires in Southern  California.
  • Signing too many power purchase agreements with renewables in the 2009 to 2014 period that were for too long of terms (e.g., 20 years instead of 10 years). PG&E is unable to take advantage of the dramatic cost decreases created by California’s bold investments. For a comparison, PG&E’s renewable portfolio costs about 20% more than SCE’s. (I am one of a few that has access to the confidential portfolio data for both utilities.)
  • Failing to act on the opportunity to sell part of its overstuffed renewable portfolio to the CCAs that emerged from 2010 to 2016. Those sales could have benefited everyone by decreasing PG&E’s obligations and providing the CCAs with existing firm resources. That opportunity has now largely passed.
  • The gas pipeline explosion in San Bruno in 2010 caused by PG&E’s failure to keep proper records for decades. PG&E was convicted of a felony for its negligence.
  • Overinvesting in obsolete distribution infrastructure after 2009 by failing to recognize that electricity demand had flattened and that customers were switching en masse to solar rooftops. (I repeatedly filed testimony starting in 2010 pointing out this error.)
  • Deploying an Advanced Meter Infrastructure (AMI) system starting in 2004 using SmartMeters that claimed that it would provide much more control of PG&E’s distribution system, and deliver positive benefits to ratepayers. Savings have largely failed to materialize, and PG&E’s inability to use its AMI to more narrowly target its PSPS illustrates how AMI has failed to deliver.
  • Acquiring and building three unneeded natural gas plants starting in 2006. Several merchant-owned plants constructed in the early 2000s are already on the verge of retiring because of the flattening in demand.
  • Failing to act in May 2000 to end the “competitive transition” period of California’s restructuring by agreeing to the market valuation of its hydropower system.
  • If PG&E had ended the transition period, it would have been immediately free to sign longer term contracts with merchant generators, thereby taking away the incentive for those generators to manipulate the market. The subsequent energy crisis most likely would have not occurred, or been much more isolated to Southern California.
  • PG&E’s CEO in 1998 made a speech to the shareholders stating that it was PG&E’s intent to extend the transition period as far as possible, to March 2001 at least. (We cited this speech from a transcript in the 1999 GRC case.)
  • Offering rebuttal in the 1999 GRC that instead confirmed the ORA’s analysis that the optimal size of a utility is closer to 500,000 customers rather than 4 million plus. Commissioner Bilas wrote a draft decision confirming this finding, but restructuring derailed the vote on the case.
  • Being caught by the CPUC in diverting $495 million from maintenance spending to shareholders from 1992 to 1997. PG&E was fined $29 million.
  • Forcing the CPUC in 1996 to adopt the “competitive transition charge” which was tied to the fluctuating CAISO day-ahead market price instead of using Commissioner Knight’s up front pay out for stranded assets. The CTC led to the “transition period” which facilitated the ability of merchant generators to manipulate the market price.
  • Two settlement agreements allow PG&E to fully recover its costs in Diablo Canyon by January 1, 1998 based on its authorized rate of return from 1986 to 1998, but also allows it to put into ratebase about half of its “remaining” construction costs as a prelude to restructuring.
  • Getting caught in 1990 telling FERC that PG&E was short resources and needed to build more, while telling the CPUC that it had a long term surplus and that it needed to curtail its payments to third-party qualifying facilities (QF) generators.
  • In the early 1980s, failing to set up a rationale process for signing QF contracts that limited the addition of these resources. In addition, PG&E missed an important pricing calculation mistake in the capacity payment term that led to a double payment to QFs.
  • In the 1970s, making many construction management mistakes when building the Diablo Canyon nuclear power plant, including reversing the blueprints, that led to the costs rising from $315 million to over $5 billion. (And Diablo Canyon in 3 of the last 5 years has operated at a loss and should not have been generating for several months each of those years.)
  • In the 1960s, signing an agreement with Sacramento Municipal Utility District (SMUD) to finance the construction of the Rancho Seco nuclear plant that essentially gave SMUD free energy when Rancho Seco wasn’t generating. The result was the mismanagement of the plant, which was so damaged that it was closed in 1989 (in part as a result of analysis conducted by the consulting team that I was on.)

The other two California IOUs are guilty of some of these same errors, and SMUD and Los Angeles Department of Water and Power (LADWP) also do not have a clean bill of health, but the quantities and magnitudes to don’t match those of PG&E.

Not so bad in our estimate…

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The University of California ARE Update published a short study that found that the drought emergency regulations adopted by the State Water Resources Control Board were only 18% more costly than the most “efficient” standards. In May 2015, the State Water Resources Control Board adopted Resolution No. 2015-0032 which imposed restrictions to reduce water use by local agencies by 4 to 36 percent depending on their circumstances. Northern California agencies were to reduce usage by 16.2 percent on average, while Southern California utilities were to reduce by 22.5 percent. In the end, Northern California utilities far exceeded their target with a 23.3 percent reduction, and Southern California’s just missed theirs with an average of 21.4 percent. M.Cubed conducted the economic study of the regulations, and found that the insurance benefits were likely substantial enough to justify the costs.

The real headline of the study should be “Drought regulations remarkably efficient!” Given that the regulations were developed in just a few months and that they were done on a prospective basis with uncertainties and unknowns (e.g., the price elasticities referenced in the study), missing the mark by only 18% is truly remarkable. In comparison, the California Air Resources Board may have missed the mark by more than 100% in setting out its AB 32 Greenhouse Gas Reduction Scoping Plan in 2008 by relying too heavily on mandated measures such as renewables generation and certain types of energy efficiencies instead of more effective market based measures.

Nevertheless, the study appears to the make mistake of making the classic economist’s joke “sure it works in practice, but does it work in theory?” Consumers are chastised for behavior that doesn’t fit the fitted values for price elasticities. The study compares the mandated and achieved reductions and notes that achieved reductions were more even across agencies than the mandates. Agencies with lower mandates achieved higher reductions, and those with higher mandates fell short on achievements. Instead of questioning the original price elasticity estimates–and such estimates commonly have a wide range and are often situation specific–the report just plows ahead as though these theoretical results should have driven human behavior.

The more interesting question the researchers should have asked given the consistent patterns in achieved versus mandated reductions is what factors caused these agencies to diverge from the mandates. Geography is clearly only part of the reason. It also appears that there is not as much “demand hardening” at the low end of use, and a higher premium put on water uses at the upper end. These factors have implications for how we should modify our price elasticity estimates.

When is $100 billion not that big?

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When it’s measured against $18,675 billion ($18.7 trillion) produced by the U.S. economy. The Heritage Foundation issued a report claiming the Obama Administration imposed $107 billion in new burdens over seven years. That sounds like a huge amount, but that’s only 0.6% (six-tenths of a percent) of the economy. And that’s spread over seven years which means that this the reduction in the GDP growth rate was only 0.08% (eight hundredths of a percent) per year. Against an annual average growth rate of over 2%, that’s a trivial amount. Another way to think of it is this way: if you had a dinner bill from Applebee’s for $19, would you not by dinner it if cost a dime more? Probably not–you wouldn’t even notice.

Plus, the HF’s estimate ignores the benefits of those regulations. This graphic from the OMB that shows the estimated relative benefits to costs of regulation.

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I won’t dig too deeply into the Heritage Foundation’s analysis other than to make a couple of notes about about alternative perspectives that I am familiar with:

  • Heritage Foundation claims that the Clean Power Plan has cost $7.2 billion as the single largest increment. Yet Lawrence Berkeley National Laboratory (which is much better qualified on this issue than the HF) just released a study showing the net financial “costs” of the various renewable portfolio standard (RPS) requirements is actually a benefit $47 to $109 billion. (And that ignores the environmental benefits identified in the report.)
  • After the 2008 financial debacle, the industry was going to face increased regulation to reign in its behavior during the previous decade. So increased regulation under Dodd-Frank is to be expected. And the better question might be what is the drag on the economy from high financial-related transaction costs? One study found that transaction costs may be as high at 45% in the U.S. economy. The financial and legal sectors likely are a bigger drag than government regulation.
  • On FCC net neutrality, see a previous post about how bigger corporations and economic concentration reduces innovation, which leads to reduced growth. Net neutrality is intended to fight that concentration.

Big Business Is Killing Innovation in the U.S. – The Atlantic

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How big business and overconcentration jams the wheels of innovation in the U.S. This is particularly relevant to encouraging new distributed energy resources on the electric utility grid–the poster child for monopolies.

Source: Big Business Is Killing Innovation in the U.S. – The Atlantic