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Direct Examination of Patrick Bowman
On behalf of the Manitoba Industrial Power Users Group (MIPUG) April 25, 2019 1
April 25, 2019
Outline
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Direct Examination of Patrick Bowman On behalf of the Manitoba - - PowerPoint PPT Presentation
Direct Examination of Patrick Bowman On behalf of the Manitoba - - PowerPoint PPT Presentation
Direct Examination of Patrick Bowman On behalf of the Manitoba Industrial Power Users Group (MIPUG) April 25, 2019 1 Outline Introduction Approach Testing application (February update) justification Assessment based on one-year
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April 25, 2019
Introduction
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Evidence comprises MIPUG Exhibits:
MIPUG-5 – Pre-filed Testimony Responses to information requests from the Consumers Coalition (CC-9), PUB (PUB-
12) and Manitoba Hydro (MH-22).
Comment on new issues arising from process. Longstanding MIPUG Assignment – Review Hydro proposals and plans in
light of regulatory principles appropriate for Crown hydro utility – long-term perspective
Fundamental view that interests of customers and Hydro should not be seen to be at
- dds. Customers need financially sufficient Hydro, Hydro needs customer loads,
competitive rates, reliable service.
Not like regulation of private sector utility, or a quasi-private utility with government investment
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April 25, 2019
Approach
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Proceeding led to challenges for analytical assessments as to whether rates are
sufficient, and are just and reasonable.
Historically, Manitoba Hydro has always been regulated on basis of long-term
financial targets.
Rates set to collect current period costs (O&M, interest on assets in service, taxes, etc.) Testing if customers were sustainably funding (or drawing down) reserves to still
permit future rate stability
In part reflects hydrology variability as discussed by MH earlier in hearing Reserves are inherently longer-term concept
Forecasts of one-year of finances is not sufficiently informative, on their own,
to draw conclusions on rate path. For this reason, concluded context was needed beyond just one-year information.
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April 25, 2019
Approach – looked at both one-year, and MH-93 path
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Relied on Exhibit MH-93
Used by Hydro as a benchmark in the Application Board found “with minor adjustments, this scenario is directionally consistent with the Board’s
decisions in this Order” (59/18, page 173)
Defensible as a long-term trajectory
Previously reviewed that MH-93 scenario showed 6 years of net losses. Existence of losses was similar to each previous IFF (as summarized in MH-93):
NFAT Scenarios for Keeyask – 8 years of losses totalling $638 million IFF14 – 8 years of losses totalling $977 million IFF15 – 3 years of losses totalling $58 million Ex. MH-93 (based on IFF16) – 6 years of losses totalling $418 million In each subsequent IFF, the start of net losses moved later, meaning higher retained earnings at
start of net loss period, better positioned to absorb losses.
Overall – NFAT expansion era is unfolding very well.
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Context - Example of Bowman direct June 2015 re: IFF14
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showed challenges. But needed to recognize scale of hurdle.
Still true for 5 impacts
being absorbed
Still no Government
support; same pile-on effect.
Operating cash flow
now far ahead of this level (now debating if this can be met in each
- f the worst years, not
just over the decade)
Retained earnings now
far exceed last estimated cost of 5 year drought.
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April 25, 2019
Testing Hydro’s Updated Application (page 6-7 of MIPUG-5)
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Hydro’s update no longer needs 3.5% increase to avoid net losses. Instead relies on 3 claims in support (Feb 14 Supplement, page 3):
- 1. Waiting for low flow to give higher rates would result in increased debt:
Mathematically true, but not the appropriate test for managing drought. Implies net income is the tool to manage drought risk. Ignores retained earnings, and PUB
comments on reserves and regulatory action as the appropriate way to manage drought.
If taken at face value, simply a directional support for perpetual large rate increases
- 2. Keeyask and Bipole III cost increases could exacerbate losses in MH-93
Noted as curious, given Bipole and Keeyask have good news compared to MH-93 Net losses in MH-93 (and each prior IFF) were well-known, and were part of rate transition
- 3. Granting rate increase now reduces likelihood of future rate shock:
Again, mathematically true, but not possible to test without long-term information No information on how likely a rate shock is, how big it might be, how much a rate increase
- f 3.5% reduces the likelihood – cannot be assessed without long-term forecasts
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April 25, 2019
One-Year Assessment - Comparison to MH-93, for 2019/20
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Key Values:
Long-term debt lower (by $0.580 billion) Capital Investment cost control shows improvement (Plant in Service down by $0.543
billion)
Retained earnings lower ($0.127 billion if no rate increase in 2019/20); one-year
drought risk for 2019/20 reduced due to known water in storage (max one-year adverse impact reduced from $432 million to $347 million)
Basically same net income ($64 million) even without the annual rate increase
assumed in MH-93. One-year assessment – basically on track even before considering 2019/20 rate increase.
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April 25, 2019
One-year Assessment – Cash (and Capitalized Interest)
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Cash flow from Operations per MIPUG-MH-8c is positive. Exceeds Normal Capital Spending. Two perspectives per MH Rebuttal : [note: this is transitory issue – IDC not typically this large]
Issues with MH approach:
- 1. Not consistent with ‘Used and Useful’ principles
- 2. Not consistent with past PUB conclusions (59/18)
- 3. Purports to show what happens when
Keeyask comes on-line – but ignores the added Revenue (approx. $360 million – PUB book, Page 76).
- 4. No principled reason to treat interest different than
- ther construction costs
More important - Hydro’s approach is not bad news – from cash perspective, this is close to a ‘post Keeyask’ picture, if you add $360 million export revenues and about $30 million extra water rentals and O&M – in short, we can cash flow a post-Keeyask year with today’s rates. (PUB/MH-I-9U)
Figure 6, Hydro Rebuttal, page 9
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April 25, 2019
Longer-Term Directional Assessment
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Compared to MH-93, key updated information:
Bipole III lower cost Keeyask earlier in-service (sooner revenues, ongoing savings).
Hard to reconcile material schedule improvement with no improvement in cost ($8.7B) when IDC
is approaching $25 million a month and camp is $1 million per day to operate. But will accept evidence of no net cost reduction.
Keeyask risks increasingly getting resolved – example of geotech Added export contracts – SaskPower 215 MW. Potential renewals of Xcel Energy/NSP
Last hearing (MH-93) evidence was no new contracts could arise or be assumed, has financial
impacts within important early years of Keeyask.
Interest rates – average interest rate slightly higher in 2019/20 (0.18%), this is before
latest debt. But, this has been locked in for much longer, so MH-93 should show sustained benefits, with much lower refinancing impacts starting within a few years.
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April 25, 2019
Longer-Term Directional Assessment (cont’d)
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DSM future unknown, but hard to see case for more upward rate pressure from DSM. MH-93
included DSM programs that are now not likely to occur (most notably Fuel Choice).
Note that just the change from the November application to February update is material – adds $30
million extra domestic revenue, offset by $12 million less export revenues, and reduced program spending $33 million in 2019/20 alone. (MIPUG/MH-2b)
All of these updates are on top of assessments already noted by the Board about why MH-93
was conservative in 59/18.
For example MH-93 did not consider export price benefits or import price reductions (2-5% in each
case) due to MMTP/GNTL (page 129 of 59/18). Also did not consider any dependability premium for uncontracted dependable export energy and had 7.9% price elasticities in load forecast.
No apparent material or sustained negative developments compared to MH-93
Not to confuse accounting detail regarding Keeyask earlier in-service with bad news.
This is not an assessment based on “hope”. This reflects latest and best updated
information.
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Other Topics
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April 25, 2019
Is negative Net Income “OK”?
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Hydro rebuttal indicates it was intended to rebut Bowman evidence that negative Net
Income is OK. Not fair summary of Bowman evidence.
Negative net income was part of each IFF since NFAT, including all Development
Plans at NFAT that included Keeyask.
Negative net income was part of Order 25-92, when PUB directed a lower rate
increase than requested by Hydro despite net losses in the IFF at that time (1992).
Negative net income was part of 2004 drought. Will always be part of droughts or
- ther risks reliant on reserves.
Also addressed by MIPUG & Coalition witnesses (Colaiacovo) at previous GRA. Obviously, positive net income is better than negative, all other things being equal, so
long as it is not the primary purpose of otherwise unneeded rate increases.
Zero or negative net income is simply a sign of reserves being sustained or drawn down, for
rate stability purposes.
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April 25, 2019
Are we “running out of time”? (transcript April 24)
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We are only running out of time if the intent is that rate increases will save Hydro
from all net losses from Keeyask and Bipole III in each year.
That is not a reasonable standard
For calculations that already include Capitalized Interest in financial calculations,
next few years will show massive improvement, not increased need for action.
Keeyask debt (main Keeyask post-in-service cash impact) already in the expense side of these
calculations
Keeyask revenue not yet in the benefits column (e.g. Cash receipts from customers). This applies to Moody’s EBIT, Moody’s EBITDA cash ratio (not focus of Hydro’s evidence,
but currently 1.2 per Moody’s), and Hydro’s cash flow calculations per Rebuttal evidence.
Similarly Bipole III deferral amortization, which will replace non-cash revenue with
cash revenue, as rates replace the deferral amortization. Increases cash flow over time
If running out of time on anything, its how to start using Hydro’s uncertainty analysis
to determine appropriate reserve levels post-Keeyask (Minimum Retained Earnings) and communicate this to stakeholders (including customers, lenders, ratings agencies)
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April 25, 2019
Cost of Service (Coalition/MIPUG-I-5)
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Recommendation is to use across-the-board adjustments for any rate increase. Reflects lack of PCOSS updated to the Test Year. Revenue:Cost information available is not sufficient for class-specific rate changes.
Reflects past fiscal year, with only Bipole III adjusted. Does not reflect what is happening in other functions. Outside of Major Capital, Hydro is spending relatively little on some functions:
Generation (CEF averages $100 million/year for sustaining Generation, on an asset base of about $7.4 billion in
PCOSS18)
Transmission (CEF averages less than $50 million/year for sustaining Transmission, on an asset base of about $2.2
billion in PCOSS18)
Distribution spending however is very large. Averages $225 million/year on an asset base of about
$2.7 billion in PCOSS18. Plus this impact is magnified on the distribution-served classes (e.g., residential, GS Small) as:
There is a smaller customer base to absorb these costs The depreciation period for these assets tends to be somewhat shorter than for Generation and Transmission.
None of this other spending is in the new PCOSS estimate. For this reason, the coarse PCOSS