Neutral Corrosion & Novinium Warranty

Dear Informed Frog-

I have been asked to pursue something in writing concerning the 50% neutral corrosion and Novinium’s warranty. I respectfully request to have this from Novinium by quitting time this Friday, January 25, 2013. Thank you in advance for your cooperation in this matter and feel free to call me with questions or problems.

Signed,

Corrosion Concern in Colorado

Dear Concerned-

Short Answer

Go to …

http://www.novinium.com/Warranty.aspx

… and search for the word “corrosion” … you won’t find it! The warranty is purposely silent on neutral corrosion.

Less Short Answer

To understand why the short answer is so short, it is really useful to understand the purpose of the neutral and the consequences of various levels of neutral corrosion on the performance and reliability of the cable. To this end, view the recording of the September 2012 Webinar or read the webinar’s companion paper, “Neutral Corrosion – Significance, Causes & Mitigation”  prepared and presented by some of the cable experts at the Insulated Conductors Committee of the IEEE that created IEEE 1617™, the IEEE "Guide for the Detection, Mitigation, and Control of Concentric Neutral Corrosion in Medium Voltage Underground Cables."

Based upon IEEE 1617 and the aforementioned webinar many circuit owners have chosen 50% corrosion as their cutoff point for rejuvenation. But you get to make that determination yourself. You need only to communicate your wishes to the Novinium masters that proide your services. If you would like to discuss your choice with an expert … you can find them at Novinium. As you will learn in the webinar the 50% rule-of-thumb is a “glass half-full” proposition, because the rate of corrosion in direct buried cables declines over time. The pessimistic “glass half empty” perspective is not supported by observation.

Even if you have the occasional neutral corrosion in excess of 50%, don’t despair. The corrosion can be pinpointed and repaired, generally at a fraction of the cost of replacement. The webinar explains that option too.

Neutral on neutrals,

Thermo

The Color of Money – Part IV

In my post of February 27^th, The Color of Money – Part I, I gave the big picture answer to Cap’s query. In February 28^th’s follow-up post we delved into the details of depreciation. On my Leap Day post we deliberated discounting. Today, in the fourth and last post of the series, we will tie up loose ends and cover the rest of the assumptions.

Rejuvenation Technology Inputs

In cells B12, B13 and B14, the name for “Product X”, the fully absorbed cost for product X, and the warranty length are entered respectively. Cells B16, B17 and B18, hold the same values for “Product Y.” Cell B20 is the ratio of the warranty length of Product Y divided by the warranty length of Product X.  The accounting lives are assumed to be the respective warranty lives.  The actual life multiplier in cell B21 is the ratio of the actual life of Product Y divided by the actual life of Product X. The warranty life is an approximate indicator of the actual life, as the technology suppliers use some combination of experience, accelerated life experiments, and accelerated life simulations to arrive at reliable life expectations.

For individual large and stable firms, such as most utilities, the spread or difference between the discount factor in cell B3 and the inflation rate in cell B6 is quite constant. If inflation increases, discount factors increase too. The 5.9% spread in the example is typical for the power distribution industry in North America.

Accounting Treatment of Warranty Remittance 

GAAP would suggest that warranty remittances are handled as negative capital expenditures. That is, the cost of replacement is reduced by the amount of the warranty remittance. Any remaining undepreciated value associated with rejuvenation is written off in the year of the failure on both the tax books and the rate-making books. Individual circuit owners may treat these warranty refunds differently. Write to me to tell me how your firm accounts for these warranty payments.  I’ll enhance the model to accommodate your method.

Residual Value

For any net present value analysis there has to be an assumption regarding the handling of residual values at the end of the analysis period. Where two rejuvenation technologies with different actual lives are compared, the technology with the longer life will have a greater residual value than the product with lesser life. For the purposes of this analysis a single replacement cycle is executed after the rejuvenation cycle has completed and future value is calculated to a one century horizon. Cash flows after 100 years are ignored. This assumption favors the technology with the shorter life, since the product with the longer life would have the greater residual value.

Bottom Line

This rigorous analysis confirms and quantifies what should be self evident. The longer the life – the greater the value.

Greener is better,

Thermonuclear Frog 

The Color of Money – Part II

In yesterday’s post, The Color of Money – Part I, I gave the big picture answer to Cap’s query. Today we will dive into the first of three sets of details that impact the answer, namely depreciation. In subsequent posts we will examine discounting and other assumptions. I had to pull out my green eyeshades to properly address depreciation. In the foreground of each of the graphs in yesterday’s post, a table of assumptions was provided.  In the illustration below I zoom in on the second table to shed light upon the details.

Depreciation is the allocation of capital cost over an accounting life of an asset. The accounting life and the actual life are not the same thing. Accounting life generally considers the actual life together with regulatory requirements and generally accepted accounting principles (GAAP). The accounting life for new cable is usually 40 years, so 40-years is the model assumption for “Replacement asset life” in cell B8.

There are a variety of ways in which the original capital cost of, say, a new cable might be spread over its accounting life of 40 years. The simplest method is called straight-line depreciation and it allocates an equal amount of depreciation expense for each of the 40 years of anticipated life. In our example, the replacement cost of $33.00 per foot in cell B7 would be spread over 40 years, and hence the annual straight-line depreciation would be 82.5¢ (i.e. $33 ÷ 40 yrs). There are other depreciation methods that accelerate expenses into the earlier years of the asset life. In my example, the double declining balance (DDB) method is used for tax purposes in cell B9. Wikipedia does a nice job of defining the concepts of depreciation, so the interested reader should visit …

http://en.wikipedia.org/wiki/Depreciation. 

Now for a not-so-secret secret – investor owned utilities keep at least two sets of books! One set of books is kept for the taxing authorities and the second set of books is kept for regulatory authorities. Often a third set of books is kept for internal purposes, but that has no impact on our analysis, because all we care about is actual cash flow.

In my next post in this series we will dive into discounting, but for now let’s agree that accelerated savings are good – a dollar saved today is worth more than a dollar saved tomorrow. That’s why for the tax books, the accountants use the most aggressive depreciation allowed by the tax authorities. For our example, I used DDB that switches to straight-line when straight-line becomes more favorable. The “2” in cell B9 represents the “Double” in “Double Declining Balance.”  The switch to straight line is controlled by a “True/False” switch in cell J9, which is not shown for brevity. If one has a depreciation expense of $100 and an “Incremental Income Tax Rate” of 32%, one would enjoy a $32 tax benefit. This is so because the $100 expense offsets $100 of revenue on which no taxes need be paid.

Now to the second set of books.  As long as the “Rate of Return on Capital” in cell B5 is greater than the “Discount Factor” in cell B3, it is to the circuit owner’s advantage to use the slowest depreciation method allowed by the regulators. In the long run the rate of return must be greater than the discount factor or investments by the circuit owner would make no sense. The FERC (Federal Energy Regulatory Commission) promulgates a Uniform System of Accounts (USoA) to regulate how capital assets are depreciated. For the example provided in this model, regulatory depreciation is straight line, indicated by a “1” in cell B10.

What if your firm is not an investor owned utility? What if your firm does not pay any income taxes? At first glance it appears that publically owned utilities should set both their incremental income tax rate and rate of return on capital to zero. That would ignore the stakeholders of public utilities have the same expectation of economic return as their investor owned neighbors. If the publically owned entity did not provide a return in the form of lower electrical rates or direct payments to a governmental unit, there would be a strong case to privatize the utility. This frog would argue that the same values used by neighboring investor-owned utilities should be utilized for this analysis, but check with the green-eyeshade guys upstairs.

Using GAAP (generally accepted amphibian practices),

T. B. Frog

The Color of Money – Part I

Dear Gregarious Green One,

My firm purchases rejuvenation services from both Novinium and UTILX. While we have a preference for the mastery displayed by your team and your inherently safer process and fluids, it is difficult for us to settle on Novinium as our sole vendor, because the UTILX price is lower. Can you help me understand your value?

Capital Concern

Dear Cap-

I’ll bet that you thought my FrogBlog tagline, ”It’s easy to be green™” focuses upon the environmental benefits of using Earth-friendly cable rejuvenation technology. Others might believe that the tag line is a play on the lyrics to that other famous frog’s song, “It’s Not Easy Being Green.” This frog is a master of the triple entendre. It’s easy to be green, while you are saving some green, and … I am not above poking fun at Kermit! Notice in the image nearby how nicely my complexion matches the color of money! That’s money that you earn when you employ superior technology.

We can provide a lower price by lowering the quality of the products and services we deliver to more closely match those of the two-decade-old approach, but we will not compromise on safety. For example, we will not use flammable fluids. But hey, there is no need to compromise safety or performance. The value of the longer post-injection reliable life and the longer warranty periods enjoyed by the patented Novinium processes and fluids can be calculated. Let’s consider two general cases.

In the first case, compare the 20-year life expectancy, warranted by the other guys, versus the 25 years enjoyed by the improved unsustained pressure rejuvenation (iUPR) process together with Ultrinium™ 732 fluid. At first glance 25-year life extension suggests a 25% increase in value, but there are the matters of the time value of money, regulated rates of return on capital, and distortions caused by the tax code. In the graph nearby I show the difference in net present value (NPV) between the two choices as a function of the post-injection reliable life. The actual value waxes and wanes depending upon the life of the cable, but for the most common case, where the life meets the expectations, iUPR enjoys more than a 10% value advantage. For other cases the value may be higher or lower, but it is generally positive.

In the second case, compare the 20-year life expectancy, warranted by the other guys, versus the 40 years guaranteed by the sustained pressure rejuvenation (SPR) process together with Ultrinium™ 732 fluid. Doubling the life extension does not double the value, because of the aforementioned time value of money, regulated rates of return, and tax code considerations. In the second graph I show the difference in net present value (NPV) between the two choices as a function of the post-injection reliable life. The actual value varies depending upon the life of the cable, but for the most common case, where the life meets the expectations, SPR has about a 16% value advantage. For other cases the value may be higher or lower, but it is always positive. For cases where the post-injection life is greater than 3 years, but the cable fails within the warranty period, the SPR/Ultrinium 732 fluid combination provides up to a 32% value advantage.

In subsequent posts, this frog will again crack open her Frogonomics 101 textbook and explain each of the factors that influence this dispassionate economic analysis. Friends of Frog (FoF) may request a copy of the MS Excel worksheet so that they can adjust the parameters of the model to calculate their unique incremental value of using state-of-the-art technology.

Always in the green,

Thermo B. Frog

DC Testing

Dear Ms. Frog,

We have been using DC testing for centuries without any problems. How do you explain that, oh wet and wise one?

Oregon Anomaly

Dear Anomaly-

DC testing of medium voltage AC cables comes up only occasionally.  I discussed the warranty impact in an April 14, 2010 post, titled “DC Testing to sectionalize faults – Warranty Impact.”  Click here to check out that post. There are many anomalies in Oregon that may never be explained, but it seems unlikely that the laws of physics are different in The Beaver State. I suppose there is a chance that everybody else is wrong and you are right. It happens to me all the time that I defend a position that is contrary to conventional wisdom.

I am actually not an expert on DC testing, so I have to rely on those that are.  One way I can be pretty sure that DC testing is inherently destructive is that the folks that manufacture and sell DC testing equipment croak along on the same chorus.  To wit, HV Diagnostics, Inc., one of the most respected suppliers of high voltage test equipment pronounces in its brochure:

“On Medium Voltage Extruded (XLPE, PE, EPR) cables, DC is no longer recommended by most international standards. DC has been found to be both destructive, causing premature failure of aged MV cables, and/or ineffective in detecting many types of serious pending insulation defects in new and old cable installations.”

You have to take that kind of pronouncement pretty seriously, because the supplier sells DC testing equipment.  As for your anomalous experience, I would recommend that you compile a comprehensive data set and use randomization and suitable controls.  Anecdotal results are inherently misleading. Also make sure that the equipment operator’s job does not depend upon the results – the guys that do testing for a living seem generally to be proponents of testing.

In cahoots with the beavers,

T. B. Frog

Middle East Query – Diagnostic Testing Timing

Dweller of the Desert asked 22 questions in his post …

Middle East Query – 22 Questions.

In this installment I address question 13.

13.   Can the customer test the cable right after injection? Could it be done immediately? If not, after how many days, weeks or months?

You are not going to like my answer, but this frog is incapable of subterfuge. There are no cable testing methods that will tell you when a cable will fail, which is what you really want to know. At best, testing will provide you a number you can track over time. An extensive U.S.A. study, the Cable Diagnostic Focused Initiative (CDFI) led by NEETRAC (The National Electric Energy Testing Research & Application Center at Georgia Tech’s College of Engineering) of commercialized cable testing methods came to this conclusion—see CDFI slide 41. The CDFI is the largest and most comprehensive study ever undertaken. All cable testing methods, except online PD testing, can cause damage to the cable insulation and shorten cable life.  Some cable testing methods such as Tan Delta or Power Factor are not comparable before and after injection, because cable injection alters the chemistry and physics of the cable, changing the measured parameters in ways counter to the claims of the diagnostic supplier.  See my 2010, September 10, post, “Cable Rejuvenation Impact on Loss Factor (tan-Delta).” In one example from that post, the tan-Delta at 0.1Hz increased after treatment, even though dielectric strength increased substantially – just the opposite of what the proprietors of the test predict. Because available diagnostics do not provide useful information and/or the tests are inherently destructive, Novinium discourages cable testing before or after cable injection. If a circuit owner chooses to test its cable despite overwhelming evidence of futility and counter productivity, before or after injection, Novinium will suspend, but not extend, any warranty for 120 after the test. Make sure you check out my 2010, November 12 post: Diagnostic Testing – Should I do it? One sneaky way to test the veracity of diagnostic firms’ claims is to request a warranty for cables which test as good, but fail. And when I say warranty, I don’t mean a credit for future diagnostics – I mean money back.  In a three-year experiment undertaken as part of the CDFI to measure the accuracy of online partial discharge testing, false negatives were about 9.5% and 19.5% for accessories and cable respectively.  False positives were 69% and 56% respectively.  I can do better than that with a role of the dice!

For now, Ma’a salama (مع السلامة/Good bye)

T. B. Frog

Neutral Corrosion Progression

Two of my disciples inquired of my July 7, 2010 post, Neutral Corrosion – How much is too much?

Dear Sheila and Kurt-

There are several different mechanisms for cable neutral corrosion.  The mechanisms are enumerated in Section 6 of IEEE 1617-2007 "Guide for Detection, Mitigation, and Control of Concentric Neutral Corrosion in Medium-Voltage Underground Cables." My colleague, Glen Bertini, was one of the participants in the ICC C7 working group that developed that document. The identified mechanisms of cable neutral corrosion in section 6 are:

1.   Galvanic corrosion

2.   Single metal corrosion

3.   Soil corrosion

4.   Differential aeration

5.   Stray currents

6.   Galvanic corrosion resulting specifically from tin coated neutral wires

Of these possible causes of neutral corrosion, soil corrosion and differential aeration are by the far the most predominant and problematic.  In both cases differences in soil chemistry along the path of the cable lead to differences in potential on exposed neutrals. Current flows in a loop through the soil and along the neutral. Copper is oxidized where the electrons leave the neutral and enter the soil and where there is oxygen (or sulfur) present. The rate of corrosion is a function of the current flow and is constrained by the availability of oxygen. Current flow, in turn, is proportional to the potential difference caused by the local differences in soil chemistry and inversely proportional to the resistance of the loop.  In the illustration nearby I show how this all works. Either from differential aeration or differences in the local soil chemistry the electrochemical potential is higher at point A than it is at point B.

As the neutral corrodes, the resistance in the loop goes up, which slows the rate of corrosion. The loss of the metallic copper itself leads to an increase of resistance. Less obviously, the non-conductive corrosion by-products (i.e. copper oxides) coat the copper surface and increase the resistance between the neutral and soil. Another set of chemical processes determine how quickly the copper oxides are transported off of the native copper surface below them. This copper-oxide transport mechanism is typically very slow in direct buried environments as the oxides are not appreciably water soluble.

At the same time the resistance is increasing, the second law of thermodynamics is at play reducing the chemical potential difference between A and B. The homogenization of chemical potential over time would occur whether or not a cable was present. Nature abhors chemical potential differences so chemical species migrate through the soil toward equilibrium – zero chemical potential difference.

Corrosion of bare concentric neutrals is highest when the neutrals are new and the soil was disturbed when the cable was installed. As some corrosion occurs and the second law reduces the chemical potential, the rate of corrosion decreases over time. In practice if the neutral has at least partially survived for several decades the rate of continuing degradation is trivial.

The other causes of neutral corrosion are much less prevalent. With the possible exception of stray currents impressed upon neutrals by active cathodic protection systems of neighboring structures (e.g. gas pipelines), all are similarly mitigated by the partial corrosion of the neutral and the equilibration of chemical potential due to the inexorable second law of thermodynamics.

If cows dragged their bulging bellies across the ground as I do they would be safe from stray current. Even with a substantial potential at the ground surface, I remain equipotential. If cows or other mammals are getting electrocuted the neutrals are entirely destroyed either locally or systematically. If the corrosion is systematic, the cables must be replaced. The source of the systematic corrosion should also be identified and eliminated – it’s not a natural phenomena; it’s man-made. Dead cows are the odd cases, but these cases get media attention, so the anecdotes are oft repeated.

In the real world, most concentric neutral corrosion is incredibly local. One or two feet of neutral become corroded. It turns out this problem is easy to diagnose and easy to repair. Diagnostic techniques are described in the aforementioned IEEE 1617-2007. A step-by-step and state-of-the-art procedure is available for free from Novinium Rejuvenation Instruction 12 (NRI 12), Electronic Cable Diagnosis and Pinpointing. Also free are step-by-step instructions (NRI 80), Neutral Corrosion Repair, that make fixing local corrosion a piece of cake. Once a local corrosion site has been pinpointed, chemistry can be employed to protect the location of the identified chemical potential difference. A suitably sized magnesium anode that has a chemical potential well above that of copper is installed as a sacrificial anode. The anode size can be adjusted to prevent neutral corrosion for any desired life.

Over twenty years of rejuvenation experience with a dearth of warranty claims in general and even fewer neutral corrosion issues specifically, provide direct evidence that whatever post-injection progression of neutral corrosion that does occur is of little practical significance.  At Novinium we have had zero failures and zero warranty claims that involved an increase of neutral corrosion after the cable was treated.

Equipotentially yours,

T. B. Frog

Projecting Future Load – Compound Growth

Dear Thermo,

Thanks for your insightful answer in your previous post, “Why does the load matter?”  How important is the future load growth?  Our planning team gives me a range instead of a single value; they suggest 2-3%.  I have sent you some real data for several of our circuits.  Teach me oh webbed one!

Still Overworked in Ohio

P.S.  Steve is actually very helpful once you get used to him.

Dear Overworked- 

Albert Einstein is said to have once quipped, “The most powerful force in the universe is compound interest.”  He was talking about money, but the same principle applies to compound growth of any kind as you shall see if you read on.

Your planners undoubtedly consider whether the geography served by the circuit is mature or whether there is still new development likely.  On top of the growth rate from new services, how are existing customer electrical demands changing?  In general, more and more electrical applications are being deployed, but greener, more energy efficient appliances may mitigate or even reverse that load growth.  Also demand management may reduce peak loads.  I picture the planners pulling out their crystal balls to determine how fast plug-in hybrid cars will be deployed.  These are just a few of the considerations in estimating future load growth.  The impact is huge, so the exercise is well worth considering.

To test that impact, let’s do a sensitivity analysis on a single 3-phase feeder circuit, your Carrollton AM-1215.  Nearby, I have plotted estimated temperature data for the circuit for most of 2010 in 30 minute increments.  The lowest curve on this graph is the ambient soil temperature at cable depth.  The temperature of the individual cables for phases A, B, and C, are displayed as fine red, grey and blue lines respectively.  The flux weighted temperature, that is the equivalent constant temperature that provides the same permeation of fluid through a cable, are the three heavy horizontal lines using the same red, grey, and blue color scheme.  I described this process generally in my previous post and I have promised a future post to examine in more detail what flux weighting means.

The next illustration of three graphs stacked on top of each other shows the extrapolation of the Carrollton AM-1215 data with 1%, 2% and 3% annual load growth.  First allow me to explain the common elements of each graph.  The x-axis is the year.  The red, grey, and blue dashed lines are projections of flux weighted amperage for phases A, B, and C respectively.  All dashed lines are plotted against the left-y-axis.  The corresponding flux weighted annual temperatures are like-colored solid lines and are plotted against the right-y-axis.  The top-most horizontal dashed line (purple) at 603 amperes is the rated ampacity of each cable.  The lower horizontal dashed line (violet) at 469 amperes is the maximum flux weighted load.  Based upon the historical difference between the peak and flux weighted temperatures for all three phases, when the flux weighted current grows to be greater than or equal to the flux-weighted maximum load, the circuit will experience significant thermal excursions above the maximum operating temperature during periods of peak load.

In the top graph of 1% annual growth, the cable is approaching its ampacity limit in the year 2050 – 40 years from now.  All is well.  In the middle graph of 2% annual ampacity growth, constraints are experienced in about 2031 or 20 years from now.  The doubling of the growth rate halved the ampacity-life of the circuit.  In the bottom graph of 3% annual ampacity growth, constraints are experienced in about 2025 or 14 years from now.

Einstein was right – the compounded growth rate is the most powerful force in the universe!  The difference between 1%, 2%, and 3% is bigger than my belly.  For the Carrollton AM-1215 circuit, 40 years of life is simply not possible in the 2% and 3% load growth scenarios unless a portion of its load is transferred to another circuit.

If you don’t expect to keep a circuit in service for 40 years, don’t ask Steve to warrant it for that long.  Ask him for a shorter life and a discount.  The cost of the technology to obtain 40 years of life is more than the cost to reach 20 years.

Compounding my own growth,

Thermo

P.S.  As for me I have never really gotten used to Steve.  His skin lacks any camouflage pattern.  I am pleased that you have learned to look the other way.  I will endeavor to be more tolerant.