Pinnacle West Capital 8K Other Events | PNW 21 Dec 07

LAW DEPARTMENT

Thomas L. Mumaw
Senior Attorney
(602) 250-2052
Direct Line

December 20, 2007

Chairman Mike Gleason
Commissioner William Mundell
Commissioner Jeff Hatch-Miller
Commissioner Kristin K. Mayes
Commissioner Gary Pierce
ARIZONA CORPORATION COMMISSION
1200 West Washington
Phoenix, Arizona 85007


Re:		Arizona Public Service Company General Rate Case; Docket Nos. E-01345A-05-0816, E-01345A-05-0826, E-01345A-05-0827; Commissioner Mayes’ Letters of November 28, 2007 and December 10, 2007, and Commissioner Pierce’s Letter of December 10, 2007.

Dear Commissioners:

Arizona Public Service Company (“APS” or “Company”) is pleased to respond to the letters received in this docket from Commissioners Mayes and Pierce related to the Company’s pending request to account for fees received under its revised Schedule 3 as Miscellaneous Service Revenues. As the Commission is aware, the Company’s requested revenue treatment is the sole difference between the Schedule 3 proposed by APS on October 24, 2007 (in response to the directive contained in Decision No. 69663) and that recommended by Commission Staff in its Memorandum and Proposed Order of November 2, 2007.¹ Importantly, while line extension applicants will pay thesameamount for service extension under both versions of Schedule 3, treating those fees as revenue compared to contributions-in-aid of construction (“CIAC”) has significant benefits to the Company and its customers in both the immediate future and in the long run—benefits not available if the Commission orders CIAC treatment of these proceeds.


¹		Staff submitted a revised Memorandum and Recommended Order on November 15, 2007, but such revision dealt with the transition plan for Schedule 3 and did not affect the issue before the Commission or the substance of Commissioner Mayes’ November 28 letter.

APS • APS Energy Services • SunCor • El Dorado • Pinnacle West Marketing & Trading, Co., LLC

Law Department, 400 North Fifth Street, Mail Station 8695, Phoenix, AZ 85004-3992
Phone: (602) 250-2052 • Facsimile (602) 250-3393
E-mail: Thomas.Mumaw@pinnaclewest.com

December 20, 2007
Page 2

The Company’s proposed accounting treatment for Schedule 3 fees will benefit the Company’s customers in at least four important ways:

	1.		It will provide a significantly larger shield to customers against both the size and frequency of future general base rate increases than would treatment of the equivalent dollars as CIAC.

	2.		It will require growth to assume a greater responsibility for paying the Company’s increasing cost of providing electric service compared to the Staff proposal.

	3.		It will improve the Company’s financial condition without increasing base rates for electric service.

	4.		By improving APS’s financial condition, it will permit the Company to more easily and economically finance the costs of providing service, including the capital costs associated with new construction—tangible benefits that will ultimately accrue to the benefit of our customers.

There is thus little question that APS’s proposed revenue treatment better serves the clear intent of Decision No. 69663 to use Schedule 3 fees to “shift the burden of rising distribution infrastructure costs away from the current customer base to growth” far better than does CIAC treatment. [Decision No. 69663 at 97.] APS provided an analysis of these issues in its October 24 filing and has also given additional detailed analyses to Staff and the Residential Utility Consumer Office (“RUCO”). Below, the Company will expand upon these points in response to the following requests made in the correspondence from Commissioners Mayes and Pierce.

Provide a comprehensive analysis of APS’s proposal for treating the Schedule 3 proceeds as revenue.

APS would note initially that this letter, in addition to the Company’s other submissions on this matter, collectively provide a thorough analysis of APS’s proposal for treating the Schedule 3 proceeds as revenue. In that regard, this letter should be read in conjunction with the information that APS provided in the October 24 filing and the APS Exceptions dated November 19, 2007. That being said, APS will take this opportunity to address some potential concerns that may be raised by Staff or other parties.

First, there is no accounting or other rule that would prevent the Commission from authorizing the Company’s proposed revenue treatment in this docket. APS rates were just recently established by Decision No. 69663 after a long and exhaustive general rate case proceeding—a proceeding that fully complied with any conceivably arguable Arizona procedural requirement, including an unequivocal and express finding of fair value rate base. That Decision explicitly directed changes to Schedule 3 that significantly increased the fees charged by APS to new electric service applicants. APS is not seeking to change those results in even the slightest degree. To the contrary, its proposed revenue treatment of those fees meets the Commission’s intent to shift the burden of rising costs to growth far

APS • APS Energy Services • Pinnacle West Energy • SunCor • El Dorado

Law Department, 400 North Fifth Street, Mail Station 8695, Phoenix, AZ 85004-3992
Phone: (602) 250-2052 • Facsimile (602) 250-3393 • E-mail: Thomas.Mumaw@pinnaclewest.com

December 20, 2007
Page 3

better than Staff’s proposed treatment. Thus, APS seeksnoincrease in Schedule 3 or any other charges that are in excess of those already established by Decision No. 69663.

While some have questioned whether this docket is the appropriate venue to resolve the issue of what accounting treatment should be afforded Schedule 3 fees, the Company believes that this ispreciselythe right proceeding in which to do so. First, as discussed above, the amount of proceeds that Schedule 3 will generate does not change whether treated as CIAC or revenue, and the Commission expressly considered and approved changes to Schedule 3 in Decision No. 69663. Second, far from requiring one type of accounting treatment or another, Decision No. 69663 is silent on the issue, leaving open the question of whether those funds should be characterized as CIAC, revenue, or some combination of the two.² But while the required accounting treatment was left unclear, the Commission was not ambiguous about itsintentwith respect to Schedule 3 funds, which Decision No. 69663 makes plain was to “shift the burden of rising distribution infrastructure costs away from the current customer base to growth.” [Decision No. 69663 at 97.] As demonstrated in detail herein, there is no question that the Company’s proposed revenue treatment achieves that intent far better than the alternative CIAC treatment, both immediately and in the long run. Moreover, as described below, no matter whether Schedule 3 fees are characterized as CIAC or revenue, the Company will not earn the allowed return on equity that was exhaustively litigated and finally approved in the recent APS rate case.

The Company’s analysis also highlights exactly why prompt determination of this issue in this proceeding is critical to both customers and the Company. The distinction in treating Schedule 3 fees as revenue versus CIAC is one that has important impacts on both the Company’s FFO/Debt ratio and its earnings. As shown in the attached Exhibit A, under the CIAC approach, the Company’s FFO/Debt ratio (a calculation discussed extensively during the rate case and other APS proceedings) hovers at 18.1% in 2008—dangerously close to the 18% FFO/Debt threshold for non-investment grade—and will fall to 17% in 2009 and 16.4% in 2010 respectively absent additional base rate relief. On the other hand, if treated as revenue, the level of Schedule 3 fees ordered in Decision No. 69663 will improve the Company’s financial health and should preserve (for the time being) the Company’s financial metrics within the BBB investment grade (though on the low end of the 18% to 28% scale).

The Company’s jurisdictional returns on equity (“ROE”) also suffer under the CIAC approach compared to the Company’s revenue proposal. As Exhibit A also shows, under the CIAC approach, absent rate relief, the Company’s ROE rests at just 7.3% in 2008 and falls to less than 6% or under by 2010. The revenue treatment increases the Company’s earnings, allowing APS to earn a ROE in the neighborhood of 8-9% between 2008 and 2010 depending on the state of the housing market, but still well below the 10.75% ROE found reasonable in Decision No. 69663. In fact, the Company’s projected jurisdictional ROEs under both options are below the ROE recommendation of every party to the rate case having such a recommendation. This analysis fully takes into account the impact of the income tax liability caused by the Schedule 3 revenue treatment.


²		As noted in the Company’s Exceptions, Schedule 3 proceeds prior to Decision No. 69663 were variously recorded as CIAC, advances-in-aid, or revenue, depending on the specific provisions of that service schedule.

APS • APS Energy Services • Pinnacle West Energy • SunCor • El Dorado

Law Department, 400 North Fifth Street, Mail Station 8695, Phoenix, AZ 85004-3992
Phone: (602) 250-2052 • Facsimile (602) 250-3393 • E-mail: Thomas.Mumaw@pinnaclewest.com

December 20, 2007
Page 4

Given the Company’s deteriorating financial condition, it is thus clear that, without prompt resolution of this matter in favor of the revenue approach, APS will have no choice but to file another rate case. Delaying resolution of this APS-specific issue to the generic hook-up fee docket (as RUCO has suggested) would be inappropriate and would negate the instant benefit that customers will see if the Commission takes this opportunity to mitigate the level of rate increases going forward.In fact, the benefit to customers fromeither the revenue or CIAC treatment of Schedule 3 fees isreduced every day that approval of Schedule 3 is delayed.

In short, the Company’s proposal is entirely consistent with the Commission’s stated intent for Schedule 3, produces no greater charges than what Decision No. 69663 would permit, and results in a jurisdictional ROE still significantly below the 10.75% ROE authorized in this docket. As explained below, these analyses suggest that customers will benefit from this treatment not just in the near term, but over a thirty year time horizon, using the same present value analysis routinely used in the Company’s planning process.

How will APS and its customers be affected by treating Schedule 3 proceeds as revenue versus CIAC? What are the positive and negative impacts to APS and its customers associated with the two options?

There is simply no question that APS’s proposed revenue treatment renders significant benefits to both customers and APS compared to CIAC in both the short term and for many years to come. APS previously discussed the impact of its proposal (versus that of Staff) on APS earnings. But the proposed revenue treatment of Schedule 3 fees also improves the Company’s credit metrics and, thus, its borrowing capacity. Attached as Exhibit B is an analysis of the relative impact of each proposal (revenue versus CIAC) on APS’s FFO/Debt ratio and also the impact of changes in that ratio on the Company’s ability to finance new utility infrastructure. Importantly, the income tax impact of increasing Schedule 3 fees (discussed at length during the proceedings in this docket) remains the same irrespective of the accounting treatment of those funds. Nevertheless, as Exhibit B clearly shows, the Company’s financial condition and its ability to carry out its public service obligations are enhanced by revenue treatment in comparison to CIAC.

Customers also benefit from the Company’s proposal compared to CIAC, both in the near term and for decades to come. Attached as Exhibit C are both a 10 year and a 30 year analysis of these two options (the latter of which is the approximate average life of new distribution plant while

APS • APS Energy Services • Pinnacle West Energy • SunCor • El Dorado

Law Department, 400 North Fifth Street, Mail Station 8695, Phoenix, AZ 85004-3992
Phone: (602) 250-2052 • Facsimile (602) 250-3393 • E-mail: Thomas.Mumaw@pinnaclewest.com

December 20, 2007
Page 5

the former captures over 100% of the present value impact on customers³). The analysis is based on the following key assumptions:

	•		The level of Schedule 3 fees, whether they are CIAC or revenue, is assumed to escalate at 5% per year. This is a conservative estimation, considering that the underlying cost per customer of new distribution plant is estimated to increase 4% and new customers are estimated to increase by roughly 3% per year—with a combined effect more in the 7% range. The higher the rate of increase in Schedule 3 fees, the more advantageous to APS customers is the revenue treatment.

	•		Rates are assumed to be reset every three years withnolag between the test period and the new rates—both highly conservative assumptions given the length of past APS rate proceedings and the degree of historic regulatory lag. Because APS customers only receive the rate base benefit of CIAC after a rate case, less frequent rate proceedings and more extensive regulatory lag would again make revenue treatment more advantageous to APS customers than shown on Exhibit C.

	•		APS’s allowed return is held constant throughout the 10 and 30 year periods. Higher allowed returns by the Commission would make the CIAC option, if one looked solely at the Schedule 3 dollars instead of the Company’s total rate base, marginally more attractive. But the higher return, when applied toallAPS rate base, would dwarf the Schedule 3 stand-alone impact and create substantiallyhigheroverall revenue requirements.

What are the conclusions that can be drawn from these analyses? First, revenue treatment is advantageous to APS customers duringeveryyear of the 10 year analysis, producing a present value benefit of some $380 to $440 million, depending on the discount rate used and assuming Schedule 3 fees of $100 million annually. Second, although in the 30 year analysis there is eventually a “cross-over” point in which CIAC treatment becomes more advantageous on a subsequent year-to-year basis (that is, an individual year in which the benefits of the revenue treatment are surpassed by those of CIAC), that point is at least some 13 years from now and depends on the Company’s rate of growth, rate of inflation, and how often base rates are reset. Moreover, there is still a relative (to CIAC) present value benefit of $250 to $300 million, assuming $100 million of annual Schedule 3 proceeds. And as noted above, if less conservative assumptions are used concerning the frequency of rate cases,


³		The “present value” analysis is one that looks at the amount of cash today that is equal in value to a payment or series of payments in the future. In other words, it calculates the worth of having that cash in hand today, rather than waiting to collect it later. The Company has computed the present value of Schedule 3 fees in two ways, both of which show significant benefits to customers. In the first set of computations, the Company used a present value rate of 12.07%, which is calculated based on the pre-tax cost of capital that the Commission determined was appropriate in Decision No. 69663. The second set of computations uses an 8% present value rate, which is the rate generally used by APS for resource planning purposes. Either approach yields substantial present value benefits to customers for the next 30 years.

APS • APS Energy Services • Pinnacle West Energy • SunCor • El Dorado

Law Department, 400 North Fifth Street, Mail Station 8695, Phoenix, AZ 85004-3992
Phone: (602) 250-2052 • Facsimile (602) 250-3393 • E-mail: Thomas.Mumaw@pinnaclewest.com

December 20, 2007
Page 6

the length of regulatory lag, and the growth rate of Schedule 3 proceeds, that cross-over year would be pushed further out and the present value benefits to APS customers increased.

With regard to new service applicants, both options have the same upfront payment impact—the customer will pay the same amount for a line extension irrespective of the Company’s accounting treatment. It should therefore not matter to such an applicant how APS categorizes the amounts paid to APS under Schedule 3. But once a new applicant joins the ranks of APS customers, that customer will enjoy the base rate-mitigation benefits that the revenue treatment affords, and is thus positively affected by the Company’s proposed revenue treatment while relatively disadvantaged by CIAC treatment.⁴

The negative impacts of CIAC are merely the converse of these positive benefits from revenue treatment. CIAC results in less of a contribution to revenue requirements from growth than does revenue, and CIAC results in deteriorated FFO/Debt with a resultant loss of financing capacity.

Will the money that APS receives be sufficient to mitigate the need for future rate relief, and if so, to what degree?

Yes, Schedule 3 fees will be sufficient to mitigate the need for future rate relief, but only if they are characterized as revenue instead of CIAC. APS customers will not see that benefit if the proceeds are treated as CIAC. Whenever the next rate case is filed, it will be for substantially less money under the Company’s revenue proposal because of the dollar for dollar reduction to revenue requirement, compared to the 12 cents to the dollar value of CIAC. The exact degree to which future rate increases will be mitigated depends on a number of factors, including the state of the housing market, the test year used in future rate cases, the rate of growth and inflation, and other factors previously discussed in this letter.

Over what time period will customers experience benefits from treating Schedule 3 proceeds as CIAC and revenue?

As previously explained in Part B, above, although the year-over-year net benefit from the revenue approach is not perpetual, with growth, it lasts formore than a decade. Present value benefits to APS customers from the APS proposal remain substantial under any viable set of assumptions for the nextthirty years. Just as APS and other utilities routinely evaluate resource and investment options in terms of relative present value costs, that is also the appropriate way to examine this issue.


⁴		Exhibit E shows projected Schedule 3 fees by customer class.

APS • APS Energy Services • Pinnacle West Energy • SunCor • El Dorado

Law Department, 400 North Fifth Street, Mail Station 8695, Phoenix, AZ 85004-3992
Phone: (602) 250-2052 • Facsimile (602) 250-3393 • E-mail: Thomas.Mumaw@pinnaclewest.com

December 20, 2007
Page 7

How do Schedule 3 changes impact the Company’s revenues over the next three years?

As shown by attached Exhibits A and D, assuming the Commission resolves this matter and approves the proposed transition plan by January 1, 2008, APS estimates that it will receive a total of $326 million in Schedule 3 fees over the next three years (using the “More Likely Scenario” for 2010). If the housing market recovers 100% by the end of 2009 and APS customer growth returns to pre-2007 levels by then, this could add another $32 million in Schedule 3 fees. How much newrevenuethis produces for APS is the decision now before the Commission. Under the Company’s proposal, both estimated revenues and proceeds would be as indicated by Exhibit D. Under the Staff recommendation, the new revenue to the Company would bezeroeven though new customers would pay the same amount under Schedule 3.

RUCO’s suggestion that revenue treatment of Schedule 3 fees might require a corresponding decrease in the electric service rates already authorized by Decision No. 69663 is inappropriate. Not only would this suggestion prevent APS from deferring or moderating another APS rate case, it entirely ignores the expressed intent of the Commission’s ordered Schedule 3 revisions. Decision No. 69663 fully authorizesboththe new base rates that the Company now charges existing customersandthe modified Schedule 3 proceeds charged to growth. Inherent in the stated intent of the Commission to use Schedule 3 funds to “shift the burden of rising distribution costs away from current customers to growth” is the understanding that the Company’scostsnecessarily are “rising” as growth continues and that the Schedule 3 proceeds should be used to shield existing customers from those rising costs. Reducing the Company’s approved electric service rates to “make-up” for the Schedule 3 revenue ignores the fact that the Company’s costshaverisen precisely as Decision No. 69663 contemplated and anticipated, and would result in even more dramatic under-earning of the Company’s authorized ROE than what APS is experiencing now. RUCO’s suggestion would also require the Commission to re-open the rate case in order to analyze exactly which tariffs, if any, should be reduced, and by what amount—a result that nobody should want and that no one has requested.

Are there any alternatives to the Company’s revenue proposal and the CIAC treatment?

Although APS strongly believes that its proposal results in a win-win situation for both customers and the Company, it acknowledges that alternative options may exist and is open to discussing other possibilities. For example, one alternative could be the imposition, where feasible, of standardized fees for extensions to each customer class (which fees would also be treated as revenue) rather than a variable fee calculated by the estimated requirements of each individual application.⁵ A uniform fee of this type would facilitate planning by future customers, ease Company and Staff administrative burdens, lessen any possible adverse competitive impact among similar businesses, and effectively focus on the overall Company revenue needs arising from growth rather than individual project costs.


⁵		For example, Schedule 3 fees charged to residential sub-developers could be set at a single flat amount, irrespective of each such applicant’s specific extension costs.

APS • APS Energy Services • Pinnacle West Energy • SunCor • El Dorado

Law Department, 400 North Fifth Street, Mail Station 8695, Phoenix, AZ 85004-3992
Phone: (602) 250-2052 • Facsimile (602) 250-3393 • E-mail: Thomas.Mumaw@pinnaclewest.com

December 20, 2007
Page 8

In considering alternative approaches, however, the Commission should bear in mind that the beneficial and mitigating rate impacts of the Company’s proposal (including the potential delay or moderation of another base rate filing) can be accomplished only through the Commission’s approval of revenue treatment at or near the amounts reflected in APS’s proposal. For this reason, the Company does not believe that an alternative where Schedule 3 proceeds are not fully reflected as revenue, such as the alternative mentioned in Commissioner Pierce’s letter of December 10, 2007, would be as beneficial for either customers or the Company as APS’s proposal. In his letter, Commissioner Pierce posits a situation wherein APS accounts for Schedule 3 fees as revenue, but assigns them a zero cost of capital—in other words, that APS treat Schedule 3 fees as a form of interest-free financing. Doing so, however, has roughly the same limited benefit to customers as the proposed CIAC treatment, which would not further the aim, as expressed in the letter, to “maximize the value of [Schedule 3 dollars] to ratepayers.” Moreover, a “zero cost of capital” proposal has detrimental impacts on the Company’s financial condition, compared even to the CIAC treatment.

To elaborate, when calculating APS’s allowed rate of return, the Commission adds the Company’s weighted cost of debt and weighted cost of equity to determine its weighted cost of capital. The weighted cost of capital is then multiplied to the Company’s rate base in order to determine APS’s required pre-tax operating income (the number that will ultimately be used to determine the Company’s revenue requirement, on which rates are based). Under the “zero cost” alternative, the Company would add a third component to the weighted cost of capital calculation: the cost of debt, the cost of equity, and a “zero cost” of Schedule 3 fees. The effect of including that zero cost component is to lower the total weighted cost of capital, which lower amount would then be applied to the Company’s entire rate base. Under this proposal, the Company’s rate base is higher (because it includes Schedule 3 fees) but its weighted cost of capital is lower. However, this yields the same total revenue requirement as applying a higher weighted cost of capital to a lower rate base—the CIAC result. In other words, the Company’s revenue requirement — before the Schedule 3 revenue reduction — is the same under both the zero cost of capital approach and the CIAC approach and thus suffers from the same drawback.

For example, assume that the Company has a hypothetical rate base of $4,000, $100 of which is Schedule 3 fees, and a weighted cost of capital (assuming an even 50/50 debt to equity balance with a 9% cost of debt and 11% cost of equity) of 10% (4.5% weighted cost of debt plus 5.5% weighted cost of equity). Under the CIAC approach, the Schedule 3 fees would reduce rate base to $3,900. The required return on the Company’s remaining rate base would thus be 10% times $3,900, or$390. Under the “zero cost” approach, the Schedule 3 fees remain in rate base, but the cost of capital would be adjusted to include the zero cost of Schedule 3 revenues, resulting in a lower weighted cost of

APS • APS Energy Services • Pinnacle West Energy • SunCor • El Dorado

Law Department, 400 North Fifth Street, Mail Station 8695, Phoenix, AZ 85004-3992
Phone: (602) 250-2052 • Facsimile (602) 250-3393 • E-mail: Thomas.Mumaw@pinnaclewest.com

December 20, 2007
Page 9

capital of just under 9.8%.⁶ This lower cost of capital, multiplied by the entire $4,000 rate base, produces a required return of roughly$390—the same as if the Schedule 3 proceeds had been treated as CIAC to begin with.

Under APS’s revenue proposal, Schedule 3 fees would offset dollar for dollar APS’s revenue requirement. If APS were directed to take its proposed approach in addition to the zero cost of capital approach, it would offset from the already reduced revenue requirement (now at CIAC levels) the total amount of Schedule 3 fees. But general regulatory accounting principles would prevent APS from recognizing the full value of that revenue on its income statement and would require the Company to “write-off” as an unrecoverable loss the great majority of the revenue stream coming from Schedule 3 fees. In fact, for every $1 of Schedule 3 revenue collected, the Company could recognize onlythirty cents.⁷ By requiring the Company to allocate a set portion of its total revenue requirement to this significantly lower-value Schedule 3 revenue stream, the proposal prevents the Company from recovering the full amount of its legitimately incurred costs through its other rates—rates that would allow the Company to earn a full return on each dollar invested, and not just 30 cents to the dollar. APS is thus detrimentally affected twice by the zero cost proposal: first by requiring a reduction to a revenue requirement that has already been reduced to CIAC levels, and second by forcing a write-off of roughly two thirds of that revenue stream. This would clearly be an unfair result. APS would be financially better off under the CIAC approach, where the same level of revenue requirements could be allocated to rates that would allow the Company full recovery on its investment.

While increasing the return above zero to any figure less than the weighted cost of capital (as calculated without regard to the Schedule 3 fees) would reduce the amount of the required write-off, it would not eliminate the need for it altogether. The only way to avoid that result would be to reduce the amount of that dollar’s credit against APS revenue requirements to a level sufficient to avoid the write-off. This would be analogous to treating part of the dollar as revenue (for rate making purposes) and part as CIAC. Although mathematically possible, this would produce significantly less customer benefit than under the Company’s proposal.


⁶	To break down this calculation, $100 of Schedule 3 fees (2.5% of the total rate base) would be included at 0%, and the remaining $3,900 would be evenly split between debt (with a cost of 9%) and equity (with a cost of 11%). The adjusted weighted cost of capital would be as follows:

		Debt:	$1,950, 48.75% of rate base, with 9% cost, produces a weighted cost of about4.4%.

		Equity:	$1,950, 48.75% of rate base, with 11% cost, produces a weighted cost of about5.4%.

		Schedule 3:	$100, 2.5% of weight base, with a cost of 0%, produces a weighted cost of0%.

	Added together, the Company’s weighted cost of capital is just shy of9.8%.

⁷	Generally speaking, a dollar received as revenue generates income on two levels: a rate of return level and a cost-recovery level. If the Commission required the Company to set the rate of return of Schedule 3 proceeds at zero, the Company would be allowed under Generally Accepted Accounting Principles to recognize as revenueonlythe cost-recovery element—roughly 30 cents to every dollar of Schedule 3 fees received. In other words, the Company would be required to write off as a loss everything on that dollar except for the present value of the depreciation return over the life of the asset. By calling the Schedule 3 fees “revenue” for the purpose of calculating revenue requirements but preventing the Company from realizing the benefit of that revenue by forcing them to take a write off, the “zero cost” proposal unnecessarily impairs the Company’s earnings at a time when APS’s ROE is already well below authorized levels.

APS • APS Energy Services • Pinnacle West Energy • SunCor • El Dorado

Law Department, 400 North Fifth Street, Mail Station 8695, Phoenix, AZ 85004-3992
Phone: (602) 250-2052 • Facsimile (602) 250-3393 • E-mail: Thomas.Mumaw@pinnaclewest.com

December 20, 2007
Page 10

As APS understands it, the concern that this identified alternative is intended to address is that APS’s revenue proposal may somehow result in a “double-payment” by customers for plant paid for from Schedule 3 fees. However, customers receive the full benefit of Schedule 3 fees being treated as revenue through the dollar-for-dollar reduction to APS’s revenue requirement. Moreover, APS (and all other utilities) has always used revenue that it receives from rates to construct new infrastructure, and Schedule 3 revenues would be no different in this regard than revenues APS obtains from, say, its E-12 (residential) or E-32 (general service) rate schedules. Thus, the Company’s Schedule 3 proposal doesnotresult in “customer-financed infrastructure” from new customers any more than does other plant paid for from money received from existing customers in the form of base rates. Rather, the “estimated cost of facilities” calculation is simply a proxy for determining the amount of the “revenue requirement” that a new customer must pay in order to be connected to the APS system, and should be treated the same way as general base rate revenues.


*		*		*		*

APS hopes that it has been responsive to the Commissioners’ inquiries and that this information will prove useful to the Commission in making this important policy decision. APS is also open to discussing these issues in greater depth at any hearing believed necessary by the Commission in this docket as part of the Company’s compliance filing. The Company continues to believe, however, that a full traditional, evidentiary hearing is not necessary. In the end, the issue is a policy decision: Should Schedule 3 be used to shift the burden of rising infrastructure costs away from existing customers or not? If the Commission believes they should—as the Order indicated it did—the Company’s proposal undoubtedly presents the best mechanism to do so. Moreover, because prompt resolution of this policy matter is vital to the Company’s ability to defer or reduce a future rate case asking and to maximize APS customer benefits, it is critical that any hearing be conducted on an expedited schedule and that this matter is resolved as quickly as possible.

Please do not hesitate to contact me should you wish further analysis or have any questions.


	Sincerely,
	/s/ Thomas L. Mumaw
	Thomas L. Mumaw

TLM/
Attachments


cc:		Ernest Johnson Elijah Abinah Dean Miller Lyn A. Farmer Christopher C. Kempley Parties of Record

APS • APS Energy Services • Pinnacle West Energy • SunCor • El Dorado

Law Department, 400 North Fifth Street, Mail Station 8695, Phoenix, AZ 85004-3992
Phone: (602) 250-2052 • Facsimile (602) 250-3393 • E-mail: Thomas.Mumaw@pinnaclewest.com

Exhibit A
12/20/07

Key Financial Metrics with Schedule 3 Fees as Revenue vs. CIAC


				$ in millions
Line				2008			2009			2010			2010
										Best			More Likely
										Case			Case
										(2)			(3)
		Schedule 3 Fees

	1	Schedule 3 fees booked as revenue — no ACC base rate increases		$	50		$	117		$	191		$	159
	2	Schedule 3 fees booked as CIAC — no ACC base rate increases		$	50		$	117		$	191		$	159

		ACC Jurisdictional Return on Equity

	3	Schedule 3 fees booked as revenue — no ACC base rate increases	(1)		8.2	%		8.8	%		9.0	%		8.4	%
	4	Schedule 3 fees booked as CIAC — no ACC base rate increases	(1)		7.3	%		6.7	%		6.0	%		5.8	%

		APS FFO to Debt (4)

	5	Schedule 3 fees booked as revenue — no ACC base rate increases	(1)		19.2	%		19.5	%		20.3	%		19.9	%
	6	Schedule 3 fees booked as CIAC — no ACC base rate increases	(1)		18.1	%		17.0	%		16.4	%		16.2	%


1		These assumptions do not include ACC retail base rate increases. A flow through to retail customers of changes in FERC transmission rates is included as are changes in the PSA.

2		Assumes complete rebound of housing market by end of 2009 and that all new meter sets will be subject to Schedule 3.

3		Assumes housing market continues to improve but has not fully recovered. Also assumes that some meter sets will continue to represent grandfathered line extensions under Staff proposed transition plan.

4		Under Standard and Poor’s guidelines for U.S. utilities and power companies, the Company must achieve an FFO to Debt ratio of 18% to 28% to maintain its current BBB rating.

Exhibit B
12/20/07

Change in FFO to Debt Ratio and Debt Borrowing Capacity
With Schedule 3 Fees Treated as Revenues vs. CIAC
$ in millions

$50 million of Schedule 3 Fees Accounted for as Revenues:


				Impact on
				FFO and
	Starting			Debt
	Point for			after
	Example			Income Taxes			Result
FFO	$	789		$	30		$	819

Adjusted debt	$	4,300		$	(30	)	$	4,270

FFO to debt		18.3	%		0.9	%		19.2	%(1)


(1)		Debt capacity would increase $160m to achieve the same 18.3% FFO to Debt ratio that was the starting point for this example.

$50 million of Schedule 3 Fees Accounted for as CIAC:


				Impact on
				FFO and
	Starting			Debt
	Point for			after
	Example			Income Taxes			Result
FFO	$	789		$	(20	)	$	769

Adjusted debt	$	4,300		$	(30	)	$	4,270

FFO to debt		18.3	%		-0.3	%		18.0	%(2)


(2)		Debt capacity would decrease $60m to achieve the same 18.3% FFO to Debt ratio that was the starting point for this example.

Exhibit C
12/20/07
Page 1

Cumulative Present Value Revenue Requirement Savings From Schedule 3 Fees
Being Treated as Revenue Versus Treated as CIAC


	($ in millions)
	First 10 Years		First 30 Years
Discounted to present value at 12.07% (1)

Per $1m of Schedule 3 fees	$	3.8	$	3.0

Per $50m of Schedule 3 fees	$	190.0	$	150.0

Per $100m of Schedule 3 fees	$	380.0	$	300.0

Per $200m of Schedule 3 fees	$	760.0	$	600.0



Discounted to present value at 8% (2)

Per $1m of Schedule 3 fees	$	4.4	$	2.5

Per $50m of Schedule 3 fees	$	220.0	$	125.0

Per $100m of Schedule 3 fees	$	440.0	$	250.0

Per $200m of Schedule 3 fees	$	880.0	$	500.0


Assumptions:		- Schedule 3 fees are collected every year
		- Growth rate of 5% in fees
		- Rate levels are reset every three years


(1)		The 12.07% discount rate represents the pre-tax cost of capital as ordered by Decision No. 69663.

(2)		The 8.00% discount rate is typically used by APS as a general planning assumption.

Schedule 3 Treatment CIAC vs. Revenue



Revenue vs. CIAC Treatment for		Exhibit C
Multiple Vintages Assuming 5% Growth of		12/20/07
Construction Costs and Schedule 3 Proceeds		Page 2

Line


5%
Growth
Factor	Change in New Rev. Req. Needed:					Year 0		Year 1			Year 2			Year 3			Year 4			Year 5			Year 6			Year 7			Year 8			Year 9			Year 10			Year 11			Year 12			Year 13			Year 14			Year 15			Year 16			Year 17			Year 18
1.000	Vintage Year	1	Line 36				—		(881	)		117			114			112			108			106			102			100			97			94			90			89			85			82			79			77			74			71
1.050	Vintage Year	2					—		—			(925	)		123			120			118			113			111			107			105			102			99			95			93			89			86			83			81			78
1.103	Vintage Year	3					—		—			—			(972	)		129			126			124			119			117			113			110			107			104			99			98			94			90			87			85
1.158	Vintage Year	4					—		—			—			—			(1,020	)		135			132			130			125			123			118			116			112			109			104			103			98			95			91
1.216	Vintage Year	5					—		—			—			—			—			(1,071	)		142			139			136			131			129			124			122			118			114			109			108			103			100
1.277	Vintage Year	6					—		—			—			—			—			—			(1,125	)		149			146			143			138			135			130			128			124			120			115			114			109
1.341	Vintage Year	7					—		—			—			—			—			—			—			(1,181	)		157			153			150			145			142			137			134			130			126			121			119
1.408	Vintage Year	8					—		—			—			—			—			—			—			—			(1,240	)		165			161			158			152			149			144			141			137			132			127
1.478	Vintage Year	9					—		—			—			—			—			—			—			—			—			(1,302	)		173			168			166			160			157			151			148			143			139
1.552	Vintage Year	10					—		—			—			—			—			—			—			—			—			—			(1,367	)		182			177			174			168			165			158			155			151
1.630	Vintage Year	11					—		—			—			—			—			—			—			—			—			—			—			(1,436	)		191			186			183			176			173			166			163
1.712	Vintage Year	12					—		—			—			—			—			—			—			—			—			—			—			—			(1,508	)		200			195			192			185			181			175
1.798	Vintage Year	13					—		—			—			—			—			—			—			—			—			—			—			—			—			(1,584	)		210			205			201			194			191
1.888	Vintage Year	14					—		—			—			—			—			—			—			—			—			—			—			—			—			—			(1,663	)		221			215			211			204
1.982	Vintage Year	15					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			(1,746	)		232			226			222
2.081	Vintage Year	16					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			(1,833	)		243			237
2.185	Vintage Year	17					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			(1,925	)		256
2.294	Vintage Year	18					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			(2,021	)
2.409	Vintage Year	19					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
2.529	Vintage Year	20					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
2.655	Vintage Year	21					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
2.788	Vintage Year	22					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
2.927	Vintage Year	23					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
3.073	Vintage Year	24					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
3.227	Vintage Year	25					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
3.388	Vintage Year	26					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
3.557	Vintage Year	27					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
3.735	Vintage Year	28					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
3.922	Vintage Year	29					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
4.118	Vintage Year	30					—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—

Change in New Rev. Req. Needed for Current Year									(881	)		(808	)		(735	)		(659	)		(584	)		(508	)		(431	)		(352	)		(272	)		(192	)		(112	)		(28	)		54			139			226			313			401			497

Cum. Chage in New Rev. Req. Needed for All Years									(881	)		(1,689	)		(2,424	)		(3,083	)		(3,667	)		(4,175	)		(4,606	)		(4,958	)		(5,230	)		(5,422	)		(5,534	)		(5,562	)		(5,508	)		(5,369	)		(5,143	)		(4,830	)		(4,429	)		(3,932	)
			30 years
Net Present Value at 12.07% of Cum.				(2,434	)
Change in New Rev. Req. Needed for All Years
NPV of same stream discounted at 8%				(1,570	)

If Rate Levels are Reset Every Three Years:
Change in New Rev. Req. Needed for Current Year									(881	)		(881	)		(881	)		(659	)		(659	)		(659	)		(431	)		(431	)		(431	)		(192	)		(192	)		(192	)		54			54			54			313			313			313

Cum. Change in New Rev . Req. Needed for All Years									(881	)		(1,762	)		(2,643	)		(3,302	)		(3,961	)		(4,620	)		(5,051	)		(5,482	)		(5,913	)		(6,105	)		(6,297	)		(6,489	)		(6,435	)		(6,381	)		(6,327	)		(6,014	)		(5,701	)		(5,388	)
			30 years

Net Present Value at 12.07% of Cum.				(3,028	)				(786	)		(1,488	)		(2,113	)		(2,531	)		(2,904	)		(3,237	)		(3,431	)		(3,604	)		(3,758	)		(3,820	)		(3,875	)		(3,924	)		(3,911	)		(3,900	)		(3,891	)		(3,840	)		(3,795	)		(3,755	)

Change in New Rev. Req. Needed for All Years

NPV of same stream discounted at 8%				(2,456	)				(816	)		(1,571	)		(2,270	)		(2,755	)		(3,203	)		(3,619	)		(3,870	)		(4,103	)		(4,319	)		(4,407	)		(4,490	)		(4,566	)		(4,546	)		(4,528	)		(4,511	)		(4,419	)		(4,335	)		(4,257	)

(Per $1,000 of Schedule 3 Fees)

Schedule 3 Treatment CIAC vs. Revenue



Revenue vs. CIAC Treatment for		Exhibit C
Multiple Vintages Assuming 5% Growth of		12/20/07
Construction Costs and Schedule 3 Proceeds		Page 3

Line


5%																																																						Vintage
Growth																																																						Year
Factor	Change in New Rev. Req. Needed:					Year 19				Year 20				Year 21				Year 22				Year 23				Year 24				Year 25				Year 26				Year 27				Year 28				Year 29				Year 30				Totals
1.000	Vintage Year	1	Line 36				67				66				63				60				57				55				51				48				45				43				39				36				1,346
1.050	Vintage Year	2					75				70				69				66				63				60				58				54				50				47				45				41				1,376
1.103	Vintage Year	3					82				78				74				73				69				66				63				61				56				53				50				47				1.402
1.158	Vintage Year	4					89				86				82				78				76				73				69				66				64				59				56				52				1,421
1.216	Vintage Year	5					96				94				90				86				81				80				77				73				69				67				62				58				1,437
1.277	Vintage Year	6					105				101				98				94				91				86				84				80				77				73				70				65				1,450
1.341	Vintage Year	7					114				110				106				103				99				95				90				89				84				80				76				74				1,453
1.408	Vintage Year	8					125				120				115				111				108				104				100				94				93				89				84				80				1,449
1.478	Vintage Year	9					133				132				126				121				117				114				109				105				99				98				93				89				1,439
1.552	Vintage Year	10					146				140				138				132				127				123				120				115				110				104				102				98				1,418
1.630	Vintage Year	11					158				153				147				145				139				134				129				126				121				116				109				108				1,387
1.712	Vintage Year	12					171				166				161				154				152				146				140				135				132				127				122				115				1,341
1.798	Vintage Year	13					183				180				174				169				162				160				153				147				142				138				133				128				1,286
1.888	Vintage Year	14					200				193				189				183				177				170				168				160				155				149				145				140				1,217
1.982	Vintage Year	15					214				210				202				198				192				186				178				176				168				163				157				153				1,131
2.081	Vintage Year	16					233				225				221				212				208				202				196				187				185				177				171				164				1,028
2.185	Vintage Year	17					249				245				236				232				223				219				212				205				197				194				186				179				908
2.294	Vintage Year	18					268				262				257				248				243				234				229				223				216				206				204				195				764
2.409	Vintage Year	19					(2,122	)			282				275				270				260				255				246				241				234				226				217				214				598
2.529	Vintage Year	20					—				(2,228	)			296				288				283				273				268				258				253				245				238				228				402
2.655	Vintage Year	21					—				—				(2,339	)			311				303				297				287				281				271				266				258				250				185
2.788	Vintage Year	22					—				—				—				(2,456	)			326				318				312				301				296				284				279				270				(70	)
2.927	Vintage Year	23					—				—				—				—				(2,579	)			342				334				328				316				310				299				293				(357	)
3.073	Vintage Year	24					—				—				—				—				—				(2,707	)			360				350				344				332				326				313				(682	)
3.227	Vintage Year	25					—				—				—				—				—				—				(2,843	)			378				368				361				349				342				(1,045	)
3.388	Vintage Year	26					—				—				—				—				—				—				—				(2,985	)			396				386				379				366				(1,458	)
3.557	Vintage Year	27					—				—				—				—				—				—				—				—				(3,134	)			416				405				398				(1,915	)
3.735	Vintage Year	28					—				—				—				—				—				—				—				—				—				(3,291	)			437				426				(2,428	)
3.922	Vintage Year	29					—				—				—				—				—				—				—				—				—				—				(3,455	)			459				(2,996	)
4.118	Vintage Year	30					—				—				—				—				—				—				—				—				—				—				—				(3,628	)			(3,628	)

Change in New Rev. Req. Needed for Current Year							586				685				780				878				977				1,085				1,190				1,296				1,407				1,518				1,636				1,753				9,859

Cum. Change in New Rev. Req. Needed for All Years							(3,346	)			(2,661	)			(1,881	)			(1,003	)			(26	)			1,059				2,249				3,545				4,952				6,470				8,106				9,859
			30 years
Net Present Value at 12.07% of Cum.			(2,434		)
Change in New Rev. Req. Needed for All Years
NPV of same stream discounted at 8%				(1,570	)

If Rate Levels are Reset Every Three Years:
Change in New Rev. Req. Needed for Current Year							586				586				586				878				878				878				1,190				1,190				1,190				1,518				1,518				1,518				7,128

Cum. Change in New Rev . Req. Needed for All Years							(4,802	)			(4,216	)			(3,630	)			(2,752	)			(1,874	)			(996	)			194				1,384				2,574				4,092				5,610				7,128
				30 years
Net Present Value at 12.07% of Cum.				(3,028)				(3,688	)			(3,628	)			(3,574	)			(3,502	)			(3,439	)			(3,382	)			(3,313	)			(3,251	)			(3,196	)			(3,134	)			(3,078	)			(3,028	)
Change in New Rev. Req. Needed for All Years
NPV of same stream discounted at 8%				(2,456)				(4,121	)			(3,995	)			(3,879	)			(3,717	)			(3,568	)			(3,429	)			(3,255	)			(3,094	)			(2,945	)			(2,770	)			(2,607	)			(2,456	)

(Per $1,000 of Schedule 3 Fees)

Exhibit D
12/20/2007

Future Revenue Requirement Increases Mitigated With Schedule 3
Fees Treated as Revenue vs. CIAC


		($ in millions)
		2008			2009			2010			2010
								Best			More
								Case			Likely Case
	Schedule 3 fees projected	$	50		$	117		$	191		$	159

FUTURE REVENUE REQUIREMENT INCREASES MITIGATED:


	Schedule 3 fees as revenue	$	50		$	117		$	191		$	159


	Schedule 3 fees as CIAC

	Schedule 3 fees reducing plant in service		(50	)		(117	)		(191	)		(159	)
	Deferred tax rate base adder		20			47			76			64

	Rate base change from current year’s fees		(30	)		(70	)		(115	)		(95	)

	Cumulative rate base change at year end		(30	)		(100	)		(215	)		(195	)

	Average rate base change		(15	)		(65	)		(158	)		(148	)

	Cost of capital with income taxes		12.07	%		12.07	%		12.07	%		12.07	%


	Cost of capital savings		2			8			19			18

	Book depreciation savings on lower average plant in service (1)		1			4			9			8

	Property tax savings on lower end of year plant in service (2)		—			1			3			3



	Schedule 3 fees as CIAC	$	3		$	13		$	31		$	29


(1)		Assuming 30-year book life

(2)		Property taxes are based on the prior year end plant balances. Assumes effective rate of 1.5% on change in plant in service.

Exhibit E
12/20/07

Revenue from Proposed Schedule 3


	2008		2009		2010		2010
					Best		More Likely
					Case		Case
Total Schedule 3 Revenue
Residential
Single	$	9,937,777	$	25,295,237	$	31,679,252	$	30,150,439
Subdivision	$	0	$	5,724,003	$	68,475,142	$	38,226,981
Multi-family	$	1,314,894	$	3,320,180	$	4,105,624	$	3,892,624
Total Residential	$	11,252,671	$	34,339,420	$	104,260,018	$	72,270,044

Non-Residential	$	38,663,218	$	82,782,753	$	86,871,593	$	86,871,593
Total	$	49,915,889	$	117,122,173	$	191,131,611	$	159,141,637

Average Revenue Per MeterSet
Residential
Single	$	10,475	$	10,869	$	11,012	$	11,157
Subdivision	$	0	$	3,025	$	3,058	$	3,092
Multi-family	$	1,273	$	1,311	$	1,325	$	1,339
Average Residential	$	5,678	$	5,086	$	3,675	$	4,021

Non-Residential	$	15,638	$	16,053	$	16,204	$	16,358

Average for all customers	$	11,207	$	9,835	$	5,667	$	6,835

Assumptions:


1)		Meter set counts assumes transition plan in effect; no revenue from subdivisions in 2008

2)		Local facilities costs based on 2006 average costs, escalated at 4% per year

3)		System facilities costs based on historical 3 yr average to mitigate the impacts of large projects such as a large substation in one year, escalated at 4% per year

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