RESPONSES	TO	EPA’s	QUESTIONS	to	DOI 1 

A. Regarding Responses to EPA 

A3. Has Reclamation or Salt River Project conducted economic modeling or 

additional analyses related to NGS economic viability under different control 

scenarios? 

Reclamation’s response: The economic analysis efforts performed to-date by NGS 

owners (through SRP) have been limited to providing accurate baseline data through 

developing supportable cost estimates for known emission retrofit scenarios. A 

determination of whether these BART changes alter the project’s economic viability can 

only be determined on an owner-by-owner basis and is different for each individual NGS 

owner. While the emphasis has been focused on BART-related financial impacts, a true 

viability assessment cannot be made by each owner until other major NGS financial 

considerations, such as lease extension costs, firming of coal prices, and other projected 

regulatory mitigation costs, are better defined. 

Question A (3) Follow‐up	Questions

a) The	response	seems	to	indicate	that	no	owners	of	Navajo	Generating	Station	(NGS),	

including	BOR,	have	done	any	economic	modeling	to	assess	the	economic	viability	of	

NGS	under	different	retrofit	scenarios.			Please	confirm	this	interpretation	of	DOI’s	

response	that	DOI	(and	BOR)	have	not	conducted	any	economic	analysis	of	the	

project	independent	of	the	other	owners.	

Reclamation’s Response:		Subsequent	to	our	original	response,	SRP	has	shared	its	

raw	data	with	the	other	NGS	co‐owners	and	each	(including	Reclamation)	is	

conducting	an	independent	evaluation	based	upon	each	owner’s	unique	situation.		

Reclamation’s	evaluation	will	be	completed	in	about	2	months	and	takes	into	

consideration	relevant	and	pivotal	cost	factors	and	assumptions	from	Reclamation’s	

point	of	view.		Our	evaluation	also	includes	MACT	considerations	and	other	details	

that	are	not	mentioned	herein.			

Some	of	the	more	critical	factors	that	must	be	considered	include,	but	are	not	

limited	to,	the	following:		BART	requirements	and	associated	costs;	the	effect	of	

EPA’s	BART	decision	on	NGS’	MACT	decisions;	expected	significant	increased	costs	

associated	with	the	pending	Navajo	Nation	lease	extension;	increased	costs	

associated	with	extending	the	coal	supply	agreement	with	Peabody	Coal;	economic	

adjustments	for	LADWP’s	imminent	departure;	and	the	uncertainty	of	the	cost	

recovery	period	(see	also	response	to	A(3)(c)	below).			

b) Does	DOI	(either	independently	or	with	BOR)	plan	to	conduct	an	analysis	of	the	

economic	viability	of	SCR	on	the	power	plant	(or	its	share	of	the	plant)	or	

specifically	any	independent	analysis	on	the	impact	of	a	BART	determination	of	SCR	

on	CAP	water	rates?		
2 

Reclamation’s response:		Please	see	response	A(3)(a)	above.		With	respect	to	water	

rates,	Reclamation	has	reviewed	and	believes	that	Central	Arizona	Water	

Conservation	District’s	(CAWCD)	estimates	are	reasonable	and	valid;	however,	these	

estimates	may	need	to	be	updated	to	include	the	mercury	MACT	retrofit	impacts	

and	differences	in	our	assumptions.	

Determining	how	to	proceed	with	MACT‐	and	BART‐related	installations	and	

modifications	are	made	even	more	difficult	because	of	as‐yet	unknown	outcomes	

associated	with	approvals,	costs	and	timing	of	other	critical	decisions	related	to	the	

operation	of	NGS	beyond	2019.		These	include	but	are	not	limited	to	a	lease	

extension	for	the	NGS	plant	property	with	Navajo	Nation,	future	coal	supply	

agreements	with	Peabody	Coal,	revision	to	Peabody	Coal’s	life	of	mine	permit,	and	

extension	of	NGS’	water	supply	agreement.		Many	of	these	involve	Federal	approvals	

which	will	add	yet	another	layer	of	timing	and	cost.			

c) If	so,	please	share	all	of	the	relevant	input	assumptions	that	would	be	used	by	

DOI/BOR	in	modeling	incremental	power	cost	and	CAP	water	rate	impacts.		

Reclamation’s response:		We	are	taking	into	consideration	assumptions	and/or	

considerations	that	include,	but	are	not	limited	to,	those	listed	below.			

o	 Cost	to	install	SCR	and	SCR	plus	BH	($550	million	[M]	to	$1.145	billion);	

o	 Cost	of	additional	annual	O&M	($12	M/yr	w/o	BH	to	$20	M/yr	w/	BH);	

o	 Increased	cost	of	producing	power	(both	in	the	interim	and	post‐2019)	as	a	

result	of	NGS	lease	extension	terms	currently	being	negotiated	between	NGS	

and	Navajo	Nation,	and	coal	supply	agreements	currently	being	negotiated	

between	NGS	and	Peabody	Coal;	

o	 Cost	recovery	under	various	scenarios,	e.g.,	short‐term	(within	5	years);	and	

long‐term	(20	to	30	years);	

o	 Financial	impact	to	co‐owners’	share	for	LADWP’s	share	of	BART‐related	

costs;	this	could	result	in	an	increase	of	5.6	%	to	Reclamation’s	share	of	

BART‐related	expenses;	

o	 Certainty	of	the	plant’s	ability	to	operate	beyond	2019	prior	to	committing	to	

any	capital	investment	for	pollution	control;	

o	 Future	regulatory	risks	including	cost	and	time	required	to	complete	

environmental	compliance	for	plant	lease	and	rights‐of‐way	renewals;	

o	 Potential	NGS	ownership	changes	in	addition	to	the	loss	of	LADWP	(e.g.,	NV	

Energy);	

o	 Cost	to	comply	with	mercury	MACT	($30	M	to	$600	M);	

o	 Cost	of	additional	annual	O&M	of	MACT	retrofits	(up	to	$3	M/yr);	

o	 No	Federal	appropriation	assistance	is	made	available;	

o	 The	risk	and	potential	cost	of	carbon	emission	control;	

o	 Cost	of	capital	(5	to	10%);	
3 

o	 Whether	or	not	cost	of	generating	power	can	all	be	recouped;	

o	 Cost	point	at	which	Navajo	surplus	power	stops	providing	value	(Market	

Rate);	

o	 Economics	of	replacing	NGS	($1.1	to	$1.2	M/MW	to	build	combined);	

o	 Economics	of	shutting	down	one	unit;	

o	 Impacts	to	Navajo,	Hopi,	and	CAP	tribes	in	particular;	and	

o	 Water	rate‐specific	considerations:	

 Effects	on	energy	component	of	CAP	rate	(Currently	$53/acre‐foot);	

 Effects	on	M&I	delivery	charge	(Currently	$137/acre‐foot);	

 Effects	on	water	related	capital	and/or	property	taxes;	

 Indirect	effects	resulting	from	reduced	water	orders;	

 Water	affordability	expectations	(maximum	$2/Acre‐Ft/	year);	

 Historic	increases	in	CAP	rates	(5.25%	for	energy	7.2%	fixed	O&M);	

 Effects	on	CAP	tribes	in	particular;	and	

 The	electricity	market	alternative;	

 Effect	on	DOI	(Reclamation)	annual	appropriation	requests	

d) The	response	states	that	a	wide	range	of	issues	would	require	better	definition	in	

order	to	develop	an	accurate	viability	assessment,	and	goes	on	to	list	some	of	those	

issues	indicating	that	some	of	the	costs	may	not	be	known	for	some	period	of	time	

into	the	future.		Although	specific	cost	figures	may	not	yet	be	available,	what	

estimated	costs	or	range	of	estimated	costs	would	DOI	suggest	using	in	an	economic	

model	to	estimate	economic	viability?	

Reclamation’s response:		Confidential	negotiations	have	been	initiated	with	the	

Navajo	Nation	on	a	lease	extension	beyond	2019	and	preliminary	discussions	also	

have	been	initiated	with	Peabody	on	extending	the	Coal	Supply	Agreement	through	

2044.		So	far,	costs	for	these	Life‐of‐Plant	extension	actions	are	within	the	same	

order	of	magnitude	as	the	amortized	annual	costs	of	SCR	implementation.		Life	of	

Plant	decisions	need	to	consider	the	additive	effects	of	all	major	actions	thereby	

increasing	the	sensitivity	of	each	on	the	plant’s	economic	viability.				

A9. Is there a surcharge to power sold from NGS that directly goes to CAP? If so, 

what is that surcharge, and how is it used by CAP? How is that surcharge 

regulated? 

Reclamation’s response: Initially, three long-term (20-year) four-party contracts for an 

estimated 400 MW of NGS surplus capacity were executed among the following: 

Western, Reclamation, CAWCD, and SRP. Through these three contracts, SRP annually 

purchased from Reclamation/Western the full United States power entitlement at the 

Navajo production cost plus paid an additional fixed annual premium of roughly $47 

million. SRP’s cost obligations increased monthly only to the degree the costs to 

produce the power increased. Under that arrangement, SRP provided power for CAP 

pumping with any SRP managed power resources it had including Reclamation’s or 

SRP’s share of Navajo power. SRP recovered its costs for providing power for CAP 
4 

pumping by billing CAWCD for the metered quantity of power used, at the Navajo 

production cost rate. 

Through two of the long-term contracts, $25.2 million from the $47 million annual fixed 

premium went to repay bonds acquired by CAWCD; this payment is referred to as the 

“Additional Rate Component,” or ARC. The ARC was legislatively authorized to go 

directly to repay bonds acquired by CAWCD (in part, to pay for construction of New 

Waddell Dam). These bonds have now been repaid and collection of the ARC ceased as 

of September 30, 2011. Under the third contract, the remaining $21.75 million were 

deposited into the Development Fund. This represents, in part, reimbursement for the 

United States’ share of NGS annual OM&R expenses as an amortization contribution 

($1,812,500 monthly, or $21,750,000 annually). Through these three contracts, the 

repayment contribution from power sales was well defined over roughly the last 20 

years. These three contracts expired September 30, 2011. Beginning October 1, 2011, 

Western will market any Navajo surplus in short and long-term contracts at market 

based electricity prices. All revenues will be deposited into the Development Fund. 

Question A (9)	Follow‐up	Questions	

a) The	response	explains	how,	historically,	SRP	received	100%	of	the	NGS	surplus	for	a	

price	consisting	of	the	cost	of	production	(at	NGS)	plus	an	additional	$47	million	

annual	fixed	premium,	then	delivered	energy	(NGS	energy	and	other	SRP	supply)	to	

the	CAP	for	which	CAWCD	paid	the	cost	of	NGS	production	based	on	metered	

quantities	of	consumed	energy.		With	SRP	no	longer	fulfilling	a	contractual	role,	how	

has	the	cost	structure	changed	as	of	the	Oct	1,	2011	arrangement?	

Reclamation’s response:		To	clarify,	under	the	expired	4‐Party	Agreement,	SRP	added	

Reclamation’s	entire share	of	NGS	energy	to	their	energy	portfolio.		The	$47	million

surcharge	consisted	of	two	separate	components.		First,	SRP	paid	a	$21.75	million	

fixed	premium	or	consideration	fee	for	the	use	of	Reclamation’s	Power	entitlement	

to	be	integrated	into	SRP’s	power	portfolio.		This	was	paid	out	at	$1,812,500	each	

month	and	deposited	into	the	Development	Fund	(Checking	Account	Side).			Second,	

SRP	paid	$25.2	million	as	an	“Additional	Rate	Component”	(ARC)	(which	was	not	

deposited	into	the	Development	Fund).		This	was	paid	out	of	a	$6/MWHR	charge	

collected	by	SRP,	which	was	paid	directly	to	a	trust	account	held	by	CAWCD	to	repay	

bonds	acquired	by	CAWCD	to	pay	for	construction	of	New	Waddell	Dam.	In	addition	

to	these	two	payments	totaling	$47	million,	SRP	paid	the	production	cost	of	

Reclamation’s	share	of	NGS	and	agreed	to	provide	CAWCD	with	the	power	needed	to	

operate	the	CAP	pumps,	for	which	SRP	billed	CAWCD	at	the	NGS	production	cost	

rate.		Through	this	arrangement,	SRP	assumed	both	the	risks	and	rewards	of	

market‐based	energy	pricing.		

Under	the	new	Western	marketing	program	which	began	October	1,	2011,	

Reclamation	receives	NGS	surplus	power	revenues	from	two	distinct	sources,	with	

Western	conducting	all	the	transactions	and	depositing	all	revenues	into	the	

Development	Fund	(Checking	Account	Side).		The	first	is	an	annual	payment	of	$25	

million	plus	the	associated	production	costs	(indexed)	for	purchase	of	select	on‐
5 

peak	power,	from	SRP	pursuant	to	a	20‐year	contract.1		The	second	is	from	

Western’s	marketing	of	the	remaining	surplus	power	at	market	rates.		This	second	

amount	will	vary	because	it	is	determined	by	the	amount	of	surplus	power	available	

to	sell,	the	market	price	for	the	power,	term	and	packaging	of	sale,	and	the	vagaries	

of	supply	and	demand	for	the	power.		Western’s	marketing	strategy	includes	selling	

the	surplus	power	in	blocks	having	variable	quantities,	duration	and	time‐of‐day,	

and	seasonality.		Western’s	directive	to	optimize	NGS	surplus	revenues	will	

sometimes	result	in	selling	surplus	power	at	market	prices	below	the	NGS	

production	cost.		As	before,	CAWCD	continues	to	pay	for	all	the	power	it	uses	to	run	

the	CAP	pumps	at	the	NGS	power	production	cost.		Also	see	more	complete	detailed	

description	of	Development	Fund	under	answer	to	question	B(3)(a).	

b) Does	the	post‐Oct	2011	arrangement	with	Western	impact	the	delivery	of	

transmission	services,	and	if	so,	how	does	DOI	project	that	may	change	the	costs	for	

CAWCD	to	receive	NGS	power?	

Reclamation’s response:		Under	normal	operating	conditions,	there	is	no	change.		

Reclamation	is	now	responsible	for	any	incremental	costs	associated	with	re‐

routing	power	due	to	outages.		Under	the	current	arrangements,	Western	will	

charge	for	any	added	costs	to	provide	alternate	routing	during	outages;	however,	

we	do	not	believe	these	costs	funded	from	the	Development	Fund	(Checking	

Account)	should	be	substantial.		(Under	the	original	4‐Party	Agreement,	SRP	was	

responsible	for	any	incremental	costs	associated	with	re‐routing	power	during	

outages.)		This	should	not	affect	CAWCD’s	power	costs	for	NGS	power,	since	they	

pay	based	on	the	production	cost.		

c) Please	provide	an	itemization	of	the	monthly	historical	payments	made	by	SRP	for	

the	NGS	surplus	power	from	2006‐2010,	to	include	a	breakdown	of	the	$47	million	

annual	fixed	premium	into	the	Additional	Rate	Component	(ARC)	contribution,	

summarizing	all	net	revenues	that	went	into	the	Fund	each	month.		Also	please	

include	all	volumes	delivered	to	SRP,	all	volumes	sold	to	market	by	SRP	(including	

prices),	and	all	volumes	of	power	delivered	to	CAWCD	for	CAP	pumping.	

Reclamation’s response:		Table	1	below,	shows	the	revenues	received	from	SRP	

under	the	4‐Party	Agreements,	and	deposited	into	the	Development	Fund	(Checking	

Account)from	2006	through	2010.		The	monthly	amounts	shown	represent	monthly	

payments	by	SRP	to	cover	Reclamation’s	share	of	NGS	power	production	costs	

which	were	billed	by	and	owed	to	SRP	as	the	operator	of	the	plant	(therefore,	the	

net	to	the	Development	Fund	Checking	Account	was	zero).		SRP’s	$21.75	million	

fixed	premium	or	consideration	fee	is	shown	as	an	annual	amount	paid	to	the	

Development	Fund	(Checking	Account	Side)	for	the	opportunity	to	receive	and	

integrate	the	Federal	NGS	power	into	SRP’s	existing	portfolio	of	power.		The	

 

1

 The original 4-Party Agreement, which expired September 30, 2011, contained a “first opportunity clause” which 

provided SRP status as priority customer for purchasing a select portion of NGS surplus power under the current 

marketing program. 
6 

Additional	Rate	Component	(ARC)	of	$25.2	million	was	paid	by	SRP	directly	to	the	

bond	trustee	for	repayment	of	CAWCD	bonds	that	provided	advances	for	the	

construction	of	New	Waddell	Dam	and	not	paid	to	the	Development	Fund.			

Table 1. Total Annual SRP Payments 2006‐2010 (in $ thousands)

Under the 4‐Party Agreement

2006 2007 2008 2009 2010

OCT 6,581 7,501 6,710 9,486 9,382 

NOV 7,018 7,249 6,905 9,868 7,731 

DEC 6,861 7,144 6,843 8,175 9,802 

JAN 7,029 8,462 7,970 10,831 11,533 

FEB 8,643 9,261 9,782 11,748 9,665 

MAR 7,588 7,734 6,477 9,592 9,443 

APR 6,668 9,399 9,122 10,805 12,082 

MAY 10,828 7,863 9,253 13,209 12,481 

JUN 6,888 7,870 8,090 9,564 9,708 

JUL 7,506 8,215 14,770 9,832 9,736 

AUG 6,992 7,955 11,505 9,303 10,107 

SEP 7,635 8,002 9,461 8,511 9,881 

TOTAL 92,243 98,662 108,896 122,933 123,561 

"Fixed Premium” Fee" 21,750 21,750 21,750 21,750 21,750 

"ARC" (Not to Fund) 25,200 25,200 25,200 25,200 25,200 

GRAND TOTAL

 

$139,193 

 

$145,612 

 

$155,846 

 

$169,883 

 

$170,511 
7 

Table 2. NGS Power Delivered to SRP 2006‐2010 and		

CAP Pumping Energy Volumes 2006‐2010 (MWH)

 2006 

(MWH) 

2007 

(MWH) 

2008 

(MWH) 

2009 

(MWH) 

2010 

(MWH) 

CAP Pumping 

Energy Volume 2,817,945 2,809,242 2,850,608 2,931,871 2,961,059 

NGS Surplus 

Energy Volume 1,444,920 1,471,529 1,407,432 990,314 1,031,332 

NGS Total Energy 

Volume to SRP 4,262,865 4,280,771 4,258,040 3,922,185 3,992,391 

Volumes Sold By 

SRP To Market 

Generally 

Not Resold 

Generally 

Not Resold 

Generally 

Not Resold 

Generally 

Not Resold 

Generally 

Not Resold 

SRP Sale Price Not 

Tracked 

Not 

Tracked 

Not 

Tracked 

Not 

Tracked 

Not 

Tracked 

d) Please	describe	the	status	of	all	power	sales	activities	since	Western	assumed	SRP’s	

prior	role	of	marketing	NGS	surplus	power,	including	contracted	volumes,	terms,	

prices	and	material	contractual	provisions	that	impact/mitigate	risk	for	the	seller.	

Reclamation’s response:		To	clarify,	SRP	did	not	market	NGS	surplus	power	before	

October	1,	2011;	pursuant	to	the	now	expired	4‐Party	Agreements,	SRP	received	use	

of	Reclamation’s	entire	share	of	NGS	energy	for	as	described	in	answer	to	A(9)(a).		

Western	did	not	assume	SRP’s	role	after	September	30,	2011;	however,	Western	is	

now	responsible	for	marketing	Reclamation’s	share	of	NGS	power	that	is	excess	to	

CAP	pumping	needs	and	that	sold	to	SRP.			

The	following	table	indicates	Western’s	NGS	surplus	power	sales	for	CY	2011	4th	

quarter.		Sales	have	been	non‐firm,	plant‐contingent,	day‐ahead,	and	for	periods	less	

than	1	month.		

It	is	important	to	note	that	roughly	50	percent	of	all	annual	NGS	surplus	power	

revenues	result	from	sales	during	the	summer	months	of	June,	July,	and	August.		

These	first	3	months	are	not	indicative	of	the	future	sales,	since	they	are	short	term,	

mostly	spot	market	sales.		Western	now	plans	to	employ	forward	(longer	term)	

sales	now	that	there	are	better	projections	of	CAP	pumping	needs.		These	long	term	

sales	transactions	should	generate	higher	revenues	

Table 3. Western Fourth Quarter 2011

			 Navajo Surplus Non‐Firm2 Power Sales

 

2

 Non-firm power is not guaranteed; it is interruptible and/or as-available. Firm power, on the other hand, is 

guaranteed and uninterruptible. Prices for non-firm power can be expected to be about 15 percent lower than for 

firm power. 
8 

Energy Sold 

MWH 

Average Non-firm 

Sale Price 

$/MWH 

Revenue 

$$ 

October 160,704 24.19 3,887,720 

November 102,201 28.81 2,555,542 

December 126,009 24.31 3,063,910 

(e) Please	provide	recent	projections	of	NGS	surplus	sales	revenues	and	projections	of	

the	dollars	anticipated	to	be	deposited	into	the	Lower	Colorado	River	Basin	

Development	Fund.	

Reclamation’s response:		The	power	market	has	been	and	continues	to	be	unusually	

weak.		For	example,	in	comparison	to	the	prices	in	the	table	above,	NGS	on‐peak	

power	was	sold	for	approximately	$140/MWH	between	June	and	August	2007.		

Western	anticipates	the	2011	4th	quarter	weighted	average	will	not	change	

significantly	during	2012.		Western	expects	to	market	the	bulk	of	Reclamation’s	

remaining	surplus	power	as	“non	firm,”	which	typically	has	a	reduced	market	value	

as	compared	to	“firm	power.”		Using	these	assumptions,	the	net	surplus	power	

revenues	for	2012	are	anticipated	to	be	approximately	$22.5	million.		Western	plans	

to	employ	forward	(longer	term)	sale	transactions	and	various	other	techniques,	

which	are	meant	to	improve	surplus	revenues	going	forward;	however	it	is	difficult	

to	predict	how	these	changes	will	affect	future	sales.		

(f) Please	confirm	that	the	$47	million	annual	fixed	premium	paid	by	SRP	has	ceased	as	

of	Oct	1,	2011.	

Reclamation’s response:		Yes,	SRP	no	longer	pays	the	$47	million	annual	fixed	

amount.		SRP’s	involvement	now	is	limited	to	one	long‐term	20‐year	contract	for	on‐

peak	power	for	a	period	of	20	years	(see	response	to	Question	A(9)(a)	above).	

B3. Can you share with us detailed financial statements for the Development and 

Cooperative Funds to help us understand how these Funds work in terms of 

current and future revenues and expenditures? 

Reclamation’s response: The Development Fund was established pursuant to section 

403 of the Colorado River Basin Project Act of 1968, as amended by the Hoover Power 

Plant Act of 1984 and the 2004 AWSA. The Development Fund was originally 

established to collect all revenues in connection with the operation of the CAP facilities. 

Revenues are collected from a number of sources including the sale of surplus NGS 

power for use in the State of Arizona. All these revenues are credited annually against 

the annual repayment obligation of the CAWCD to the United States for construction of 

the CAP. CAWCD is responsible for the repayment obligation of the project and pays the 

United States a cash payment to make up any shortfall from collected revenues to the 

Development Fund during the calendar year. However, if, in any year, the revenues 
9 

derived from the sale of surplus power exceed the annual repayment obligation, the 

excess funds are allocated first to the payment of fixed OM&R for the delivery of CAP 

water used by Arizona Indian Tribes. Section 107 of the AWSA provides for the 

distribution of those excess revenues (see Section 107 language, Attachment 3). All 

expenditures from the Development Fund are limited to those authorized by the AWSA. 

The Cooperative Fund was established in the Treasury of the United States by Section 

313 of the Southern Arizona Water Rights Settlement Act of 1982 (SAWRSA) and 

reauthorized in the 2004 AWSA. Approximately $10.5 million were deposited into the 

Cooperative Fund from various settlement parties at the time the fund was established. 

The fund is invested and managed by the Office of the Special Trustee, Department of 

the Interior, pursuant to SAWRSA for the benefit of the Tohono O’odham Nation. 

Allowable expenditures from the Cooperative Fund are amounts determined by the 

Secretary of the Interior (Secretary) to be necessary to carry out the obligations of the 

Secretary under SAWRSA, including paying the variable cost (energy) component for 

the delivery of CAP water ordered by the San Xavier and Schuk Toak Districts of the 

Tohono O’odham Nation. The fixed OM&R costs associated with delivery of CAP water 

are paid from the Development Fund pursuant to the AWSA. If funds are not available 

from the Development Fund to pay the fixed OM&R costs, the total cost associated with 

delivery of CAP water to the two Districts will be paid from the Cooperative Fund. It is 

important to note that only interest earned on the original investment income or revenues 

derived from the sale or lease of effluent or effluent credits can be expended from the 

Cooperative Fund. 

Question B (3)	Follow‐up	Questions	

a) The	response	does	not	directly	respond	to	the	request	for	financial	information.		

Please	provide	detailed	financial	information	regarding	the	Development	and	

Cooperative	funds	including,	if	available,	annual	financial	statements	or	similar	

documentary	evidence	of	income	and	expense	for	the	funds.		

Reclamation’s Response:		After	reflecting	on	our	answers	regarding	the	Development	Fund,	

we	felt	it	was	important	that	we	give	a	more	complete	description	of	the	Development	

Fund	and	how	it	operates.		The Lower Colorado River Basin Development Fund (Development 

Fund) was established pursuant to Section 403 of the Colorado River Basin Project Act of 1968, 

as amended by the Hoover Power Plant Act of 1984 and the Arizona Water Settlements Act, 

Public Law 108–451, December 10, 2004 (AWSA). It was originally established to collect all 

authorized revenues associated with the CAP facilities, as well as pay for certain CAP-related 

expenditures. Revenues that are deposited into the Development Fund (Checking Account Side) 

are collected from a number of sources including CAWCD3

 annual repayment obligation, and 

sale of Reclamation’s share of NGS power which is surplus to the needs of the CAP (referred to 

as NGS surplus power). Expenditures paid from the Development Fund (Checking Account 

Side) include NGS power generation costs associated with Reclamation’s share of power 

produced, NGS transmission-related expenses, and NGS oversight costs. Called the 

Development Fund collectively, it functions in a way as both as a “checking” account and a 

 

3

CAWCD presently operates the CAP and is responsible for repaying the Federal government for the non-Federal 

share of the CAP’s capital (construction) costs; currently CAWCD’s repayment obligation is approximately $55M 

each year. 
10 

“money-market” account. The “checking” account tracks the revenues and expenditures on a 

calendar year basis. The “money market” account consists of deposits from the “checking” 

account of any net revenues that exist as of December 31st each year. These funds are then used 

to fund Federal obligations established by the AWSA. The “checking” account function of the 

Development Fund is tracked by a Source and Disposition of Funds report which is prepared by 

Reclamation’s Lower Colorado Regional Office on a monthly basis (see Exhibit 1 of the 

Attachment). 

Various aspects and components of the Development Fund are not particularly straightforward; 

therefore, we provide some additional information concerning a few key aspects of the 

Development Fund and how it works, below. 

 CAWCD’s Repayment Obligation. CAWCD is responsible for repaying the Federal 

government for a portion of the costs related to construction of the CAP, pursuant to a 

Master Repayment Agreement. Reclamation bills CAWCD annually in January for the 

current year’s repayment obligation (see Exhibit 2 of the Attachment). The annual 

repayment obligation is based upon an amortized repayment schedule (see Exhibit 3 of 

the Attachment). Although CAWCD is responsible for the entire annual payment, net 

revenues in the Development Fund’s annual “checking” account as of December 31st of 

the previous year are used to offset this obligation. That is to say, the “Total Funds 

Available for Repayment” identified in the Source & Disposition of Funds December 

statement in Exhibit 1 is then applied against the estimated $55M repayment obligation, 

as reflected in Reclamation’s annual bill to CAWCD (noted on line entitled “TOTAL 

CREDIT DUE ($28,351,189)” in Exhibit 2). Both the net revenue from the “checking” 

account (that is applied towards CAWCD’s repayment obligation) and CAWCD’s 

payment, for the remaining balance due of the current year’s repayment obligation, are 

then moved to the “money-market” account side of the Development Fund. At least until 

2046 (when CAWCD’s repayment obligation will be considered as paid off), there will 

continue to be revenue deposited into the “money-market” account side of the 

Development Fund, equal to the amount of CAWCD’s annual repayment obligation. 

 Revenues from NGS Surplus Sales. As of October 1, 2011, Western is responsible for 

the marketing and sale of NGS surplus power.4 One long-term 20-year contract for NGS 

surplus power has been entered into with SRP for purchase and use of a select portion of 

on-peak NGS surplus power for $25 million annually plus its associated production costs 

(indexed). This sale was available to SRP under the original 4-Party Agreement, which 

contained a “first opportunity clause” providing SRP status as a priority customer under 

the current marketing program. 

 Collection of Reclamation’s Portion of NGS Expenses. SRP, which is one of the owners 

of the NGS, is also responsible for its operation and upkeep, including ensuring 

compliance with all regulatory requirements. As the NGS operator, SRP bills 

Reclamation monthly for NGS operation, maintenance, and replacement costs (OM&R 

costs, also referred to as NGS power production costs), based upon Reclamation’s 24.3 % 

 

4

 Prior to October 1, 2011, sale and use of NGS surplus power were governed by a 4-Party Agreement, the details of 

which are provided in our response to EPA’s follow-up question A.A(x)(y). 
11 

share of the power produced by the plant. As of October 1, 2011, Reclamation then bills 

CAWCD for the NGS power reserved by CAWCD to operate the CAP system, based 

upon the NGS OM&R costs paid by Reclamation. These production cost payments, 

made by CAWCD to Reclamation, are deposited into the Development Fund’s “checking 

account”; they are then disbursed during the calendar year towards payment of 

Reclamation’s share of NGS power production costs. Power production costs associated 

with NGS surplus power are paid from revenues generated into the checking account 

from various sources. 

Section 107 of the AWSA provided additional authority to fund various activities rather than 

return the “checking account” funds at the end of the year to Treasury. All AWSA 

expenditures authorized under the settlement are funded from the Development Fund (money 

market side). Disbursements are made according to priorities established by the AWSA, which 

grouped the disbursements into two “cascades.” 

 First Cascade – Includes all revenues received from the “checking account side” up to the 

CAP repayment amount. Disbursements are allowed based on the following set of 

priorities: 

1. Fixed OM&R charges associated with the delivery of CAP water to Indian tribes; 

2. Gila River Indian Community Water OM&R Trust Fund and Rehabilitation of 

Indian portion of San Carlos Irrigation Project (SCIP); 

3. The following without regard to priority, except New Mexico paid first: 

 New Mexico Unit Fund 

 GRIC – PMIP Construction (CAP Project) 

 Tohono O’odham CAP projects 

 San Carlos Apache CAP project 

 SCIDD Lining (Non-Indian SCIP Rehabilitation 

 Future Indian Water Settlement Subaccount 

 Federal Firming Costs 

 Federal cost to implement 

4. Payment of the costs of constructing CAP distribution systems for non- settlement 

tribes. 

 Second Cascade – Was established to recognize that years might exist where revenue 

from NGS surplus power sales, “checking account,” might exceed the CAP repayment. 

These revenues had a separate priority structure for disbursement as follows: 

1. Fixed OM&R charges associated with the delivery of CAP water to Indian tribes; 

2. Final year’s payment on CAP repayment obligation; 

3. U.S Treasury General Fund to reimburse fixed OM&R costs for CAP Indian 

deliveries and Indian water rights previously paid from the Development Fund; 

4. U.S Treasury General Fund to 9(d) debt made non-reimbursable under Settlement 

Act; 

5. U.S Treasury General Fund. 

The Cooperative Fund is not managed by Reclamation and is really only tangentially 

impacted and we do not believe it is relevant to these discussions. 
12 

	 	

To	help	illustrate	how	the	Development	Fund	works,	Attachment	1	to	these	

responses	includes	three	exhibits:	

 Exhibit	1	is	a	copy	of	the	Development	Fund’s	“Source	and	Disposition	of	Funds”	

for	the	period	ending	December	2011,	which	includes	a	list	of	specific	revenues	

(sources)	and	expenses	(dispositions)	that	flow	into	and	out	of	the	Development	

Fund,	along	with	a	short	description	of	these	entries.	

 Exhibit	2	is	a	copy	of	Reclamation’s	bill	to	CAWCD	for	its	2012	CAP	repayment	

obligation.		This	bill	identifies	the	amount	credited	towards	CAWCD’s	2012	

annual	obligation,	based	upon	the	net	balance	of	the	Development	Fund’s	on	

December	31,	2011.	

 Exhibit	3	is	a	copy	of	the	amortization	schedule	for	CAWCD’s	annual	payments.		

		

B4. How much will revenues from surplus power sales decrease if SCR were 

required on one unit, 2 units, and 3 units? 

Reclamation’s response: Installation of SCR would add to energy production costs, 

since Reclamation would be responsible for 24.3 percent of the total SCR installation 

costs. It is difficult, however, to determine what the net revenue impacts would be if SCR 

is required on one, two, or all three units at NGS other than to say net revenues from 

surplus power sales would decrease. Net revenues to the Development Fund equal the 

difference between power production costs and revenues from sale of surplus power 

generation. Roughly one-third of Reclamation’s share of the megawatt-hours generated 

at NGS ends up as surplus power; however, as of October 1, 2011, Western will market 

NGS surplus power in short- and long-term contracts at market-based electricity prices. 

Due to market price fluctuations, it is not possible to estimate NGS surplus power net 

revenues going forward. 

Question B (4)	Follow‐up	Questions	

a) The	response	states	that	revenues	from	surplus	power	sales	will	decrease	if	SCR	is	

required	since	the	difference	between	production	cost	and	market	price	would	be	

reduced	due	to	added	production	cost.		In	comparison	to	prior	years,	where	SRP	was	

responsible	for	sales	of	excess	power,	has	DOI/BOR	completed	any	analysis	to	

determine	how	market	prices	themselves	would	have	impacted	Fund	revenues	if	

the	current	agreement	with	Western	had	been	in	place	historically,	perhaps	for	the	

most	recent	5	years?	

Reclamation’s response:		Please	note	that	in	prior	years,	SRP	was	NOT	responsible	

for	sale	of	excess	power;	rather,	SRP	obtained	use	of	Reclamation	energy	produced	

at	the	plant.		Reclamation	did	a	“back‐cast”	look	taking	into	consideration	historical	

market	values.		The	results	were	based	on	the	assumption	that	50	%	of	the	sales	

would	have	occurred	off‐peak	and	the	rest	on‐peak.		The	most	dramatic	market	
13 

effect	observed	was	roughly	$10	million	in	lost	revenue.		The	study	was	performed	

almost	2	years	ago	and	did	not	include	year	2011.	

b) What	wholesale	market	price	forecast	is	DOI/BOR	consulting	when	it	calculates	

potential	lost	revenues	going	forward?		When	was	that	forecast	produced	and	what	

are	the	monthly	price	projections?			

Reclamation response:		Western	and	Reclamation	consult	the	U.S.	Energy	

Information	Administration	(EIA)	as	well	as	other	forecast	providers	and	natural	

gas	forecasts.		We	are	particularly	interested	in	pricing	forecasts	for	the	Palo	Verde	

and	Mead	trading	hubs,	which	are	near	where	the	majority	of	NGS	sale	transactions	

are	based.		Western	has	advised	that	the	monthly	market	value	for	power	in	2012	

should	closely	track	the	Palo	Verde	Index	weighted	average	observed	during	

calendar	year	2011,	provided	below.		The	low	prices	we	are	experiencing	currently	

are	considered	unusual.	

Table 4. PALO VERDE INDEX WEIGHTED AVERAGE PRICE		

FOR CALENDAR YEAR 2011

YEAR 2011 Firm 2011 Non-Firm

MONTH ON PEAK OFF PEAK ON PEAK OFF PEAK

JANUARY $34.38 $24.33 $25.00 $20.00 

FEBRUARY $35.21 $23.58 $39.00 $5.00 

MARCH $28.44 $36.64 $36.00 $14.49 

APRIL $34.67 $18.84 $44.00 $17.26 

MAY $35.05 $14.59 $34.72 $12.86 

JUNE $38.85 $9.34 $30.00 $9.65 

JULY $44.77 $21.21 $47.00 $20.03 

AUGUST $42.75 $25.25 $38.28 $15.00 

SEPTEMBER $40.18 $25.01 $18.67 $12.00 

OCTOBER $34.56 $23.74 $57.00 $21.80 

NOVEMBER $33.57 $24.48 $48.00 $21.80 

DECEMBER $32.00 $25.24 $28.94 $28.00 
14 

B. Regarding Responses to NREL 

1(c). By what budgetary mechanisms did the federal government pay for its share 

of the original cost of NGS and for subsequent emission control additions? 

Reclamation’s response: Reclamation used CAP construction appropriations to fund the 

original cost of NGS and installation of the SO2 scrubbers. These costs were allocated 

to project purposes as reimbursable costs. CAP reimbursable costs are being repaid to 

the United States annually over a 50-year time period by CAWCD, the entity currently 

responsible for operating the CAP. Subsequent emission controls were included as part 

of the annual operation, maintenance, and replacement expenses for which Reclamation 

was billed for its share (24.3%). Reclamation’s share of NGS OM&R expenses was 

initially paid from the Lower Colorado Basin Development Fund (Development Fund).

Question 1 (c)	Follow‐up	Questions	

a) The	response	states	that	Reclamation’s	share	of	OM/R	expenses	were	originally	paid	

from	the	Lower	Colorado	River	Basin	Development	Fund.		Is	that	no	longer	the	case?			

Reclamation’s response:		Yes,	OM&R	is	paid	out	of	the	Development	Fund	as	

described	in	answer	to	question	B(3)(a).			Remember,	CAWCD	pays	to	the	

Development	Fund	(Checking	Account)	the	costs	of	production	for	energy	used	for	

CAP	purposes.		

b) If	so,	how	are	they	paid	today?		See	answer	to	B(3)(a)	above

Question 1 (c)	Follow‐up	Questions	

a) Does	the	option	to	use	CAP	construction	appropriations	(as	was	done	for	the	SO2	

scrubbers)	remain	open	for	future	incremental	capital	costs	associated	with	

environmental	upgrades?	

Reclamation’s response:		In	the	late	1990s,	when	the	original	NGS	SO2	scrubber	

installation	work	was	required,	the	CAP	project	had	not	yet	been	placed	into	

repayment	status	and	the	final	costs	for	construction	of	the	entire	CAP	(canals,	

pumping	plants,	NGS,	etc.)	was	still	under	discussion.			Ultimately,	both	entities	

agreed	that	it	was	appropriate	to	seek	Federal	appropriations	as	part	of	the	

construction	costs	of	the	project.				CAWCD’s	repayment	obligation	calculations	

included	these	costs	as	part	of	the	entire	cost	of	CAP	construction.		Low	NOx	burners	

were	installed	a	decade	later	after	the	project	was	placed	into	repayment	status	and	

Federal	appropriations	were	not	considered	appropriate;	therefore,	these	costs	

were	included	in	the	OM&R	component	of	the	NGS	operating	costs.		Absorbing	these	

costs	into	OM&R	for	NGS	without	creating	significant	budgetary	impacts	on	CAP	

water	users	was	possible	at	the	time	only	through	the	deferral	of	other	planned	NGS	

OM&R	actions.		
15 

While	Reclamation	believes	any	further	cost	at	NGS	for	BART	or	other	OM&R	

activities	is	the	responsibility	of	CAWCD	as	part	of	OM&R,	the	possibility	of	Federal	

appropriations	has	not	been	completely	ruled	out	by	some	as	a	way	to	soften	or	

offset	the	initial	funding	for	BART	compliance.		If	ultimately	funded	by	CAWCD	as	an	

OM&R	expense,	it	would	be	recovered	by	passing	these	costs	on	to	CAP	water	users	

through	increases	to	the	Energy	Rate	component	of	CAP	water	rates.	

1(d) How much excess power from NGS has the Western Area Power 

Administration (Western) sold on the government’s behalf annually over the 

past 15 years, and what were the values of those sales annually? 

Reclamation response: Over the last 15 years, the Central Arizona Project has received 

a net of about $47 million annually. Three long-term (20-year) four-party contracts for an 

estimated 400 MW of NGS surplus capacity were executed among the following: 

Western, Reclamation, CAWCD, and SRP. Western did not actively market (sell) any 

NGS Surplus during this period, other than their efforts at the front end of crafting the 

three original Four-Party contracts Through these three contracts, SRP annually 

purchased from Reclamation/Western the full United States power entitlement at the 

Navajo production cost plus paid an additional fixed annual premium of roughly $47 

million. SRP’s cost obligations increased monthly only to the degree the costs to 

produce the power increased. On an annual basis. the revenues received for operational 

costs were netted out to zero within the overall LCBDF accounting because CAWCD 

disbursements offset the SRP deposits . Under that arrangement, SRP provided power 

for CAP pumping with any SRP managed power resources it had including 

Reclamation’s or SRP’s share of Navajo power. SRP recovered its costs for providing 

power for CAP pumping by billing CAWCD for the metered quantity of power used, at 

the Navajo production cost rate. 

Through two of the long-term contracts, $25.2 million from the $47 million annual fixed 

premium went to repay bonds acquired by CAWCD; this payment is referred to as the 

“Additional Rate Component,” or ARC. The ARC was legislatively authorized to go 

directly to repay bonds acquired by CAWCD (in part, to pay for construction of New 

Waddell Dam). These bonds have now been repaid and the ARC has stopped being 

collected as of September 30, 2011. Under the third contract, the remaining $21.75 

million are deposited into the Development fund. This represents, in part, reimbursement 

for the United States’ share of NGS annual OM&R expenses as an amortization 

contribution ($1,812,500 monthly, or $21,750,000 annually). Through these three 

contracts, the repayment contribution from power sales was well defined over roughly 

the last 20 years. 

These three contracts expired September 30, 2011. Beginning October 1, 2011, 

Western will market any Navajo surplus in short and long-term contracts at market 

based electricity prices. All revenues will be deposited into the Development Fund . 

Question 1 (d)	Follow‐up	Questions		

a) Of	the	annual	400	MWs	allotted	to	SRP,	what	was	the	annual	average	amount	of	

MWs	used	for	CAP	pumping?	
16 

Reclamation’s response:			Please	see	Table	2	in	response	to	Question	A(9)(3)	above	

which	indicates	the	annual	CAP	pumping	energy	volume,	in	MWH,	for	2006,	2007,	

2008,	2009,	and	2010,	as	well	as	the	annual	surplus	energy	volume	for	those	same	

years.	

b) How	did	SRP	cover	its	$47	million	annual	fixed	premium	if	the	volume	of	water	sold	

to	CAWCD	was	sold	at	the	cost	of	production?	

Reclamation’s response:		Under	the	4‐Party	Agreement	(which	expired	

September	30,	2011),	SRP	was	able	to	use	(for	its	own	purposes)	all	of	

Reclamation’s	share	of	power	and	agreed	to	provide	power	for	CAP	pump	load.		

Availability	of	this	surplus	power	provided	SRP	with	additional	flexibility	in	

managing	its	entire	portfolio.		Additionally,	SRP	could	recover	this	premium	through	

the	rate	structure	it	charged	to	all	SRP	customers.		We	believe	SRP	was	able	to	

realize	a	net	savings	which	would	otherwise	not	have	been	available.		

c) Was	SRP	by	contract	restricted	from	selling	NGS	power	on	the	western	wholesale	

market?		

Reclamation’s response: 	SRP	was	not	restricted	from	selling	NGS	surplus	power;	

however,	SRP	has	a	significant	retail	load	to	serve	its	customers	and	likely	only	a	

small	amount	would	have	been	marketed.	

Question 1 (d)	Follow‐up	Questions	

a) Under	the	new	NGS	surplus	contract	(Oct	1,	2011)	is	a	set	portion	of	the	revenue	

from	excess	power	sales	($21.75	million)	to	continue	to	be	set	aside	in	the	Lower	

Colorado	River	Basin	Development	Fund	for	amortization	of	CAWCD	repayment	

obligation?		

Reclamation response:		With	the	expiration	of	the	4‐Party	Agreement	on	September	

30,	2011,	SRP	no	longer	pays	the	$21.75	million	fixed	premium	or	consideration	fee.		

As	indicated	in	response	to	Question	A(9)(a),	under	the	new	Western	marketing	

program,	Reclamation	receives	into	the	Development	Fund	(Checking	Account)	NGS	

surplus	power	revenues	from	two	distinct	sources.		The	first	source	is	an	annual	

payment	from	SRP	of	$25	million	(indexed)	pursuant	to	a	20‐year	contract	for	

purchase	of	select	on‐peak	power.		The	second	source	is	revenue	generated	from	

Western’s	sale	of	the	remaining	surplus	power	on	the	open	market.		There	is	no	set	

aside.		

b) What	happens	if	the	amount	of	revenue	obtained	from	excess	power	sales	exceeds	

the	set	aside?			
17 

Reclamation’s response:		As	explained	above	there	are	no	“set‐asides.”		Whatever	net	

revenues	exist	at	the	end	of	the	calendar	year	are	applied	to	CAWCD’s	repayment	

obligation	and	retained	in	the	Development	Fund	for	the	long	term	purposes	

authorized	under	AWSA.	

1(e). Please provide a description of the new excess power marketing contract that 

will be in place in October 2011. 

Reclamation response: The new contract divides up responsibilities among Western, 

Reclamation & CAWCD. It assigns future NGS surplus marketing responsibilities to 

Western and Reclamation. Responsibility for managing CAP pump load has been 

transferred to CAWCD, including scheduling, delivery, regulation, balancing, reserves, 

and their associated costs. Revenues collected for excess energy sales under the new 

contract will depend on the net of market pricing and power production costs at the time 

of the sale. All revenues from the sale of Reclamation’s NGS surplus power will be 

deposited into the Development Fund. Western and Reclamation have already made 

one sale of excess power to SRP. SRP purchased surplus NGS capacity and energy to 

be taken between the months of June and August of each year beginning 2012 until 

September 30, 2031. SRP will pay $25 million escalated each year for this power. 

Question 1 (e)	Follow‐up	Questions	

a) Please	provide	additional	information	regarding	the	SRP	seasonal	surplus	power	

purchase,	including	the	annual	volumes	and	rate	of	escalation.			

Reclamation’s response:		SRP’s	First	Opportunity	Contract	results	in	SRP	acquiring	

300MW	of	a	super‐peak	product	annually,	defined	as	an	8‐hour	energy	product,	7	

days	per	week	for	the	months	of	June	through	August,	up	to	220,800	MWH	per	year.	

The	annual	premium	starts	out	at	$25	million	in	the	first	year	and	escalates	annually	

at	3	%.		The	premium	will	be	reset	one	time	after	10	years	on	a	formula	based	on	the	

ratios	of	forward	natural	gas	prices	and	the	3	%	escalation	will	continue	for	the	last	

10	years	of	the	contract.		SRP	is	required	to	pay	the	actual	production	costs	for	this	

power,	with	the	cost	escalation	increases	capped	at	4	%	per	year,	reset	to	actual	

costs	every	4	years.			

		

b) Please	indicate	the	date	that	the	transaction	was	priced,	point	of	receipt	and	any	

ancillary	charges	paid	by	SRP	or	the	seller.		

Reclamation’s response: The	new	contract	prices	and	terms	are	based	upon	an	

effective	date	of	October	1,	2011,	with	SRP	primarily	taking	delivery	of	this	acquired	

NGS	surplus	at	substations	near	Phoenix	(Westwing)	and/or	near	Hoover	Dam	

(Mead),	as	well	as	other	mutually	agreed	to	points.		Any	ancillary	charges	are	the	

responsibility	of	SRP	as	the	customer.

2(b). What is the breakdown of the revenues into and out of the Lower Colorado 

River Basin Development Fund each of the past 5 years? What are the revenue 

projections and assumptions for the next 5 years? 
18 

Reclamation response: See table below. 

DEVELOPMENT FUND REVENUES AND USES (2002-2016) 

Dollars ($1,000) 

YEAR REVENUE STREAM INVESTMENT 

REVENUE (1) 

EXPENSES (2) 

2002 58,744 0 0 

2003 50,032 0 0 

2004 54,634 0 0 

2005 69,222 4,139 0 

2006 45,282 13,407 0 

2007 51,282 16,711 0 

2008 59,248 7,451 0 

2009 55,363 501 0 

2010 66,562 461 156,424 

2011 68,165 8,223 79,721 

2012 55,311 8,156 97,729 

2013 54,458 7,471 136,943 

2014 53,604 5,971 110,357 

2015 57,768 4,955 123,921 

2016 56,747 3,731 152,319 

Question 2 (b)	Follow‐up	Questions	

a) The	table	provided	for	the	Lower	Colorado	River	Basin	Development	Fund	Revenue	

and	Expenses	seems	to	reflect	an	increasing	trend	of	expenses	exceeding	revenues.		

Is	this	correct?			

Reclamation response:		These	long‐term	funding	obligations	were	created	as	a	result	

of	the	AWSA	and	vary	over	time.		During	the	first	10	years,	the	expenses	shown	are	

closely	tied	to	construction	projects	and	are	increasing	in	nature.		These	expenses	

are	not	related	in	any	way	to	the	OM&R‐related	expenses	at	NGS	and	come	from	the	

money	market	side	of	the	Development	Fund.		

b) If	so,	is	there	a	contingency	plan	to	re‐adjust	revenues	and	expenses	in	order	that	

the	Fund	remains	whole?	

Reclamation’s response:		The	authorized	expenditures	of	Development	Fund	(Money	

Market	Side)	revenues	under	the	AWSA	vary	over	time.		Expenses	include	

construction	activities	that	have	a	definite	end‐date,	while	payments	of	fixed	OM&R	

for	tribal	water	uses	will	continue	to	increase.		The	structure	of	the	AWSA	

recognized	that	over	time	the	fund	may	not	be	sustainable	and	other	mechanisms	

might	need	to	be	explored.		Revenues	in	excess	of	the	$55	million	repayment	

obligation	from	NGS	surplus	power	sales,	although	not	a	guaranteed	source	of	

revenue,	were	anticipated	to	be	one	possible	solution	for	meeting	the	potential	

shortfall.	
19 

3(f). Please explain the financial mechanism for using Reclamation’s portion of 

NGS power for CAP. 

Reclamation response: As explained in # A. 1) d. above, prior to September 30, 2011, 

each year on a monthly basis, SRP purchased from Reclamation/Western all Navajo 

surplus power and power used for CAP pumping, at the Navajo production cost, plus a 

fixed annual premium of roughly $47 million. Under that arrangement, SRP provided 

power for CAP pumping with any SRP managed power resource it had including 

Reclamation’s or SRP’s share of Navajo power. SRP then billed CAWCD for the 

metered quantity of power used, at the Navajo production cost rate. From the roughly 

$47 million recovered, a portion of the premium ($25.2 million) was used to repay bonds 

(the ARC). These bonds have been repaid, and the $25 million are no longer collected. 

The remaining $21.75 million were deposited into the Development Fund to be applied 

towards CAWCD’s annual repayment to the Federal government. 

Beginning October 1, 2011, this process changed. The United States’ portion of NGS 

power now is divided into two types: reserved and surplus. CAWCD manages and pays 

Reclamation for reserved power at the NGS production cost. The remaining production 

costs, plus a profit, are expected to be recovered by Western through sales of surplus 

NGS power. The full revenue from Western surplus power sales will be transferred to 

Reclamation for deposit into the Development Fund. If CAWCD is somehow able to 

recover any profit from its management of reserved power, this profit will also be 

transferred to Reclamation for deposit into the Development Fund. The net revenues 

above cost in the Development Fund are credited annually against the annual 

repayment obligation of CAWCD to the United States for construction of the CAP. 

CAWCD is responsible for the repayment obligation of the project and pays the United 

States a cash payment to make up any shortfall from collected revenues to the 

Development Fund during the calendar year. 

Question 3 (f)	Follow‐up	Questions	

a) Prior	to	Oct	1,	if	SRP	paid	for	Reclamation/Western’s	share	of	NGS	at	the	value	of	

the	cost	of	production	plus	a	$47	million	annual	fixed	premium,	then	resold	the	

power	to	CAWCD	at	‘the	cost	of	production,’	how	was	the	$47	million	recovered	if	

the	buy/sell	arrangement	was	set	at	the	cost	of	production?			

Reclamation’s response:		SRP’s	sale	of	Reclamation’s	share	of	NGS	power	at	the	

power	production	cost	rate	applied	only	to	the	power	delivered	to	CAWCD	for	

pumping	CAP	water.		SRP	had	no	pricing	restrictions	on	its	use	of	the	remaining	

portion	of	Reclamation’s	share	of	NGS	(approximately	1.4TWh	per	year).		

b) Who	paid	the	$47	million	annual	fixed	premium	value	needed	to	make	SRP	whole?			

Reclamation’s response:		As	we	have	attempted	to	clarify	in	our	response	to	Question	

A(9)(a)	above,	prior	to	October	1,	2011,	SRP	paid	$21.75	million	as	a	fixed	premium	

or	consideration	fee	for	the	use	of	Reclamation’s	entire	share	of	NGS	power,		and	

$25.2	million	Additional	Rate	Component	to	the	Bond	Trustee.		In	return,	SRP	
20 

provided	all	the	power	required	to	operate	the	CAP	system	and	deliver	CAP	water	to	

CAWCD’s	customers,	billing	CAWCD	at	the	NGS	production	cost	rate.		SRP	was	able	

to	add	to	its	own	portfolio	Reclamation’s	entire	share	of	NGS.		Due	to	SRP’s	large	

customer	base,	SRP	could	recover	this	premium	through	the	rate	structure	it	

charged	to	its	customers.			

Question 3 (f)	Follow‐up	question		

a) In	the	answer	to	Question	1(d),	it	is	stated	that	the	$21.75	million	deposited	in	the	

Development	Fund	was	used	for	“reimbursement	for	the	United	States’	share	of	NGS	

annual	OM&R	expenses.”		In	Question	3	(f),	it	is	stated	that	the	same	$21.75	million	

was	used	for	“CAWCD’s	annual	repayment	to	the	Federal	Government.”		How	are	

these	two	statements	consistent?			

Reclamation’s response:		Please	see	the	Reclamation’s	response	to	Question	A(9)(a).		

Question 3 (f)	Follow‐up	Question	

a) Again,	it	is	stated	in	the	second	paragraph,	“The	revenue	in	the	Development	Fund	is	

credited	annually	against	the	annual	repayment	obligation	of	CAWCD	to	the	United	

States	for	construction	costs	of	the	CAP.”	(emphasis	added)		Under	this	scenario,	

who	and	how	are	payments	made	for	annual	OM&R	expenses,	including	the	OM&R	

expense	linked	to	the	ownership	share	of	Reclamation/Western?		

Reclamation’s response:		The	answers	to	previous	questions	should	now	adequately	

address	this	question.
LOWER COLORADO RIVER BASIN DEVELOPMENT FUND Exhibit 1

SOURCE & DISPOSITION OF FUNDS

PROJECT 1225 FUND V40

FOR THE PERIOD ENDING DECEMBER 2011

Available for Repayment CALENDAR YEAR

MONTH AVAILABLE CALENDAR YEAR CALENDAR YEAR AVAILABLE

I SOURCES OF FUNDS DECEMBER ADJUSTMENTS DECEMBER TO DATE 2011 ADJUSTMENTS FOR REPAYMENT

a Navajo Miscellaneous Revenue [1] 

b Navajo Surplus Sales [1] 

c Calpine 

d Parker Davis 

e Transmission Line Loss Revenue (Miscellaneous) 

Navajo Energy Charge (NEC) 

f CAWCD Applied Advance (1CU30-P1212) [2] 

Navajo Consideration Fee 

d Hoover 4.5 Mills 

g SO2 Credit Sales - 

h EPA Credit 

i Right of Use/Miscellaneous - Available 

SRP Interest from O&M Bills 

j Non-Recurring Items - 

Total Sources of Funds - Available for Repayment 

II DISPOSITION OF FUNDS

Right of Use Expense & Licenses - Available - - - - - - 

SO2 Credit Sales - - - - - - 

a Salt River Project - Navajo Generating Station

i Capital Equipment 

ii Insurance Expense 

iii O&M Expense 

iv Materials & Supplies 

v Fuel 

vi Coal Expense 

vii Indenture of Lease 

viii Litigation 

b Transmission Systems

i Arizona Public Service - Southern O&M 

ii Arizona Public Service - Southern Capital 

iii Nevada Power - Western 

iv Liberty Phase Shifter 

v McCullough Switching Station - SRP 

v McCullough Switching Station - CAWCD 

vi WAPA - CAP Transmission 

c Navajo Oversight 

i WAPA Oversight - Four Party Agreemen 

ii WAPA Navajo Surplus Sales - P1212 

ii WAPA Trans Purchases - P1212 

iii USBR 

Non-Recurring Items 

Total Dispositions of Funds - Available for Repayment 

NET INCREASE/DECREASE IN AVAILABLE FOR REPAYMEN 

INTEREST 

INTEREST CAWCD ADVANCE PAYMENTS 

TOTAL FUNDS AVAILABLE FOR REPAYMENT 

Not Available for Repayment CALENDAR YEAR

MONTH NOT AVAILABLE CALENDAR YEAR CALENDAR YEAR NOT AVAILABLE

SOURCES OF FUNDS DECEMBER ADJUSTMENTS DECEMBER TO DATE 2011 ADJUSTMENTS FOR REPAYMENT

CAWCD McCullough Reimbursement 

CAWCD Repayment Obligation 

CAWCD Reimbursement for Oversight 

CAWCD Advance (1CU30-P1212) [2] 

SO2 Credit Sales 

Right of Use/Miscellaneous - Not Available 

Non-Indian Revenue/Advances 

Recreation Admin Reimbursement (credited in workplan) 

Non-Recurring Items [3] 1 

Total Sources of Funds - Not Available for Repayment 

DISPOSITION OF FUNDS

O&M CAWCD Contract Administration 

O&M Federal Interest Oversight 

O&M CAWCD Requested Work 

McCullough Switching Station - CAWCD 

Right of Use Expense & Licenses - Not Available 

Trans to R344 - AWSA 

Non-Indian Costs 

Non-Recurring Items 

Total Dispositions of Funds - Not Available for Repayment 

NET TOTAL FUNDS NOT AVAILABLE FOR REPAYMEN 

FUND BALANCE ACTIVITY - DECEMBER 

FUND BALANCE ACTIVITY - BEGINNING OF PERIOD 

FUND BALANCE ACTIVITY - ENDING OF PERIOD 

FOOTNOTES

[1] Navajo Surplus Sales - $824,080.32 payment from the City of Los Angeles was for surplus Navajo energy. This was recorded as "Misc Revenue" by WAPA; therefore this is

 being reclassified as Navajo Surplus Sales on the S&D.

[2] CAWCD Advance - Although $9,204,826 was applied in December for November's advance this was actually reflected on November's S&D; therefore the $9,204,826

 is not reflected on December's S&D

[3] Non-Recurring Items - $12 million payment from CAWCD pursuant to Section 6(d)(ii) of the Stipulation Agreement. Payment shall be applied as a prepayment of the las

 $12 million due on the non-interest bearing portion of CAWCD's repayment obligation

CAP2011.xlsx DEC

2/6/2012

Year Stage I Stage II Stage I Stage II Principal Interest Total Interest Bearing Non-Interest Baring 

1994 915,777,096 - 338,712,077 - 12,544,892 8,926,537 21,471,429 915,777,096 338,712,077 

1995 903,253,776 - 338,690,505 - 12,544,892 30,186,741 42,731,633 903,253,776 338,690,505 

1996 891,712,185 - 337,687,205 - 12,544,892 29,801,021 42,345,913 891,712,185 337,687,205 

1997 880,231,495 286,140,529 336,623,003 105,832,798 16,464,625 32,206,491 48,671,116 1,166,372,024 442,455,801 

1998 868,884,835 282,220,796 335,424,771 105,832,798 16,464,625 38,469,950 54,934,575 1,151,105,631 441,257,569 

1999 857,507,127 278,301,062 334,257,587 105,832,798 16,464,625 37,958,710 54,423,335 1,135,808,189 440,090,385 

2000 845,889,604 274,381,329 333,330,219 105,832,798 16,464,625 37,439,455 53,904,080 1,120,270,933 439,163,017 

2001 834,463,848 270,461,596 332,211,083 105,832,798 20,228,093 36,926,608 57,154,701 1,104,925,444 438,043,881 

2002 819,255,489 266,541,863 331,111,083 105,832,798 20,228,093 36,287,347 56,515,440 1,085,797,352 436,943,881 

2003 804,047,129 262,622,129 330,011,083 105,832,798 20,228,093 35,648,087 55,876,180 1,066,669,258 435,843,881 

2004 788,838,770 258,702,396 328,911,083 105,832,798 21,404,013 35,008,826 56,412,839 1,047,541,166 434,743,881 

2005 773,630,411 253,606,743 327,811,083 105,832,798 21,404,013 34,330,266 55,734,279 1,027,237,154 433,643,881 

2006 758,122,052 248,511,090 327,011,083 105,832,798 21,404,013 33,641,680 55,045,693 1,006,633,142 432,843,881 

2007 742,613,692 243,415,436 326,211,083 105,832,798 21,404,012 32,953,093 54,357,105 986,029,128 432,043,881 

2008 727,105,333 238,319,783 325,411,083 105,832,798 25,167,480 32,264,507 57,431,987 965,425,116 431,243,881 

2009 707,833,506 233,224,130 324,611,083 105,832,798 25,167,479 31,450,146 56,617,625 941,057,636 430,443,881 

2010 688,561,680 228,128,477 323,811,083 105,832,798 25,167,481 30,635,785 55,803,266 916,690,157 429,643,881 

2011 669,289,853 223,032,823 323,011,083 105,832,798 26,343,400 29,821,424 56,164,824 892,322,676 428,843,881 

2012 650,018,026 216,761,250 322,211,083 105,832,798 26,343,400 28,967,763 55,311,163 866,779,276 428,043,881 

2013 630,746,199 210,489,677 321,411,083 105,832,798 26,343,399 28,114,103 54,457,502 841,235,876 427,243,881 

2014 611,474,373 204,218,104 320,611,083 105,832,798 26,343,401 27,260,443 53,603,844 815,692,477 426,443,881 

2015 592,202,546 197,946,530 319,811,083 105,832,798 31,361,357 26,406,782 57,768,139 790,149,076 425,643,881 

2016 567,912,762 191,674,957 319,011,083 105,832,798 31,361,356 25,385,422 56,746,778 759,587,719 424,843,881 

2017 543,622,979 185,403,384 318,211,083 105,832,798 31,361,356 24,364,061 55,725,417 729,026,363 424,043,881 

2018 519,333,196 179,131,811 317,411,083 105,832,798 32,929,250 23,342,701 56,271,951 698,465,007 423,243,881 

2019 494,843,412 171,292,344 316,811,083 105,832,798 32,929,249 22,262,257 55,191,506 666,135,756 422,643,881 

2020 470,353,629 163,452,878 316,211,083 105,832,798 32,929,250 21,181,813 54,111,063 633,806,507 422,043,881 

2021 445,863,845 155,613,411 315,611,083 105,832,798 32,929,250 20,101,370 53,030,620 601,477,256 421,443,881 

2022 421,374,062 147,773,944 315,011,083 105,832,798 40,456,185 19,020,926 59,477,111 569,148,006 420,843,881 

2023 389,357,343 139,934,478 314,411,083 105,832,798 40,456,185 17,688,933 58,145,118 529,291,821 420,243,881 

2024 357,340,625 132,095,011 313,811,083 105,832,798 40,456,185 16,356,939 56,813,124 489,435,636 419,643,881 

2025 325,323,906 124,255,545 313,211,083 105,832,798 42,808,025 15,024,945 57,832,970 449,579,451 419,043,881 

2026 293,157,188 114,064,238 312,761,083 105,832,798 42,808,025 13,609,340 56,417,365 407,221,426 418,593,881 

2027 260,990,469 103,872,932 312,311,083 105,832,798 42,808,025 12,193,735 55,001,760 364,863,401 418,143,881 

2028 228,823,751 93,681,625 311,861,083 105,832,798 42,808,025 10,778,130 53,586,155 322,505,376 417,693,881 

2029 196,657,032 83,490,319 311,411,083 105,832,798 44,062,514 9,362,524 53,425,038 280,147,351 417,243,881 

2030 163,235,825 73,299,012 310,961,083 105,832,798 44,062,514 7,904,994 51,967,508 236,534,837 416,793,881 

2031 129,814,617 63,107,706 310,511,083 105,832,798 44,062,514 6,447,464 50,509,978 192,922,323 416,343,881 

2032 96,393,409 52,916,399 310,061,083 105,832,798 44,454,487 4,989,934 49,444,421 149,309,808 415,893,881 

2033 62,951,402 42,333,119 309,631,883 105,832,798 44,454,487 3,518,609 47,973,096 105,284,521 415,464,681 

2034 29,488,594 31,749,840 309,223,483 105,832,798 44,454,488 2,046,588 46,501,076 61,238,434 415,056,281 

2035 - 21,166,560 304,840,869 105,832,798 44,454,488 707,386 45,161,874 21,166,560 410,673,667 

2036 - 10,583,280 270,969,661 105,832,798 44,454,487 353,693 44,808,180 10,583,280 376,802,459 

2037 - - 237,098,454 105,832,798 44,454,487 - 44,454,487 - 342,931,252 

2038 - - 203,227,246 95,249,519 44,454,488 - 44,454,488 - 298,476,765 

2039 - - 169,356,038 84,666,239 44,454,487 - 44,454,487 - 254,022,277 

2040 - - 135,484,831 74,082,959 44,454,488 - 44,454,488 - 209,567,790 

2041 - - 101,613,623 63,499,679 44,454,488 - 44,454,488 - 165,113,302 

2042 - - 67,742,415 52,916,399 44,454,487 - 44,454,487 - 120,658,814 

2043 - - 33,871,208 42,333,119 44,454,487 - 44,454,487 - 76,204,327 

2044 - - - 31,749,840 10,583,280 - 10,583,280 - 31,749,840 

2045 - - - 21,166,560 10,583,280 - 10,583,280 - 21,166,560 

2046 - - - 10,583,280 10,583,280 - 10,583,280 - 10,583,280 

 6,957,918,536 22,958,297,071 14,721,539,734 4,815,392,312 1,646,462,500 971,347,529 2,617,810,029

Payment Due Balance

Beginning Balance Beginning Balance

Interest Bearing Non-Interest Bearing
LOWER COLORADO RIVER BASIN DEVELOPMENT FUND Exhibit 1

SOURCE & DISPOSITION OF FUNDS

PROJECT 1225 FUND V40

FOR THE PERIOD ENDING DECEMBER 2011

Available for Repayment CALENDAR YEAR

MONTH AVAILABLE CALENDAR YEAR CALENDAR YEAR AVAILABLE

I SOURCES OF FUNDS DECEMBER ADJUSTMENTS DECEMBER TO DATE 2011 ADJUSTMENTS FOR REPAYMENT

a Navajo Miscellaneous Revenue [1] 

b Navajo Surplus Sales [1] 

c Calpine 

d Parker Davis 

e Transmission Line Loss Revenue (Miscellaneous) 

Navajo Energy Charge (NEC) 

f CAWCD Applied Advance (1CU30-P1212) [2] 

Navajo Consideration Fee 

d Hoover 4.5 Mills 

g SO2 Credit Sales -

h EPA Credit 

i Right of Use/Miscellaneous - Available 

SRP Interest from O&M Bills 

j Non-Recurring Items 

Total Sources of Funds - Available for Repayment 11,251,465.75 - 11,251,465.75 168,872,577.35 168,872,577.35 - 

II DISPOSITION OF FUNDS

Right of Use Expense & Licenses - Available - - - - - - 

SO2 Credit Sales - - - - - - 

a Salt River Project - Navajo Generating Station

i Capital Equipment 

ii Insurance Expense 

iii O&M Expense 

iv Materials & Supplies 

v Fuel 

vi Coal Expense 

vii Indenture of Lease 

viii Litigation 

b Transmission Systems

i Arizona Public Service - Southern O&M 

ii Arizona Public Service - Southern Capital 

iii Nevada Power - Western 

iv Liberty Phase Shifter 

v McCullough Switching Station - SRP 

v McCullough Switching Station - CAWCD 

vi WAPA - CAP Transmission 

c Navajo Oversight 

i WAPA Oversight - Four Party Agreemen 

ii WAPA Navajo Surplus Sales - P1212 

ii WAPA Trans Purchases - P1212 

iii USBR 

Non-Recurring Items - - - - - 

Total Dispositions of Funds - Available for Repayment 11,082,152.24 - 11,082,152.24 140,939,874.36 140,939,874.36 - 

NET INCREASE/DECREASE IN AVAILABLE FOR REPAYMEN 169,313.51 - 169,313.51 27,932,702.99 27,932,702.99 - 

INTEREST 77,556.81 77,556.81 366,711.36 366,711.36 

INTEREST CAWCD ADVANCE PAYMENTS 21,375.29 21,375.29 51,774.31 51,774.31 

TOTAL FUNDS AVAILABLE FOR REPAYMENT 169,313.51 98,932.10 268,245.61 27,932,702.99 28,351,188.66 418,485.67 

Not Available for Repayment CALENDAR YEAR

MONTH NOT AVAILABLE CALENDAR YEAR CALENDAR YEAR NOT AVAILABLE

SOURCES OF FUNDS DECEMBER ADJUSTMENTS DECEMBER TO DATE 2011 ADJUSTMENTS FOR REPAYMENT

CAWCD McCullough Reimbursement 

CAWCD Repayment Obligation 

CAWCD Reimbursement for Oversight 

CAWCD Advance (1CU30-P1212) [2] 

SO2 Credit Sales 

Right of Use/Miscellaneous - Not Available 

Non-Indian Revenue/Advances 

Recreation Admin Reimbursement (credited in workplan) 

Non-Recurring Items [3] 

Total Sources of Funds - Not Available for Repayment 13,696,549.26 - 13,696,549.26 42,808,476.42 42,808,476.42 - 

DISPOSITION OF FUNDS

O&M CAWCD Contract Administration 

O&M Federal Interest Oversight 

O&M CAWCD Requested Work 

McCullough Switching Station - CAWCD 

Right of Use Expense & Licenses - Not Available 

Trans to R344 - AWSA 

Non-Indian Costs 

Non-Recurring Items 

Total Dispositions of Funds - Not Available for Repayment 103,902.80 - 103,902.80 57,565,292.96 57,565,292.96 - 

NET TOTAL FUNDS NOT AVAILABLE FOR REPAYMEN 13,592,646.46 - 13,592,646.46 (14,756,816.54) - (14,756,816.54)

FUND BALANCE ACTIVITY - DECEMBER 13,761,959.97

FUND BALANCE ACTIVITY - BEGINNING OF PERIOD (586,073.52)

FUND BALANCE ACTIVITY - ENDING OF PERIOD 13,175,886.45

FOOTNOTES

[1] Navajo Surplus Sales - $824,080.32 payment from the City of Los Angeles was for surplus Navajo energy. This was recorded as "Misc Revenue" by WAPA; therefore this is

 being reclassified as Navajo Surplus Sales on the S&D.

[2] CAWCD Advance - Although $9,204,826 was applied in December for November's advance this was actually reflected on November's S&D; therefore the $9,204,826

 is not reflected on December's S&D

[3] Non-Recurring Items - $12 million payment from CAWCD pursuant to Section 6(d)(ii) of the Stipulation Agreement. Payment shall be applied as a prepayment of the las

 $12 million due on the non-interest bearing portion of CAWCD's repayment obligation

CAP2011.xlsx DEC

2/6/2012

Year Stage I Stage II Stage I Stage II Principal Interest Total Interest Bearing Non-Interest Baring 

1994 915,777,096 - 338,712,077 - 12,544,892 8,926,537 21,471,429 915,777,096 338,712,077 

1995 903,253,776 - 338,690,505 - 12,544,892 30,186,741 42,731,633 903,253,776 338,690,505 

1996 891,712,185 - 337,687,205 - 12,544,892 29,801,021 42,345,913 891,712,185 337,687,205 

1997 880,231,495 286,140,529 336,623,003 105,832,798 16,464,625 32,206,491 48,671,116 1,166,372,024 442,455,801 

1998 868,884,835 282,220,796 335,424,771 105,832,798 16,464,625 38,469,950 54,934,575 1,151,105,631 441,257,569 

1999 857,507,127 278,301,062 334,257,587 105,832,798 16,464,625 37,958,710 54,423,335 1,135,808,189 440,090,385 

2000 845,889,604 274,381,329 333,330,219 105,832,798 16,464,625 37,439,455 53,904,080 1,120,270,933 439,163,017 

2001 834,463,848 270,461,596 332,211,083 105,832,798 20,228,093 36,926,608 57,154,701 1,104,925,444 438,043,881 

2002 819,255,489 266,541,863 331,111,083 105,832,798 20,228,093 36,287,347 56,515,440 1,085,797,352 436,943,881 

2003 804,047,129 262,622,129 330,011,083 105,832,798 20,228,093 35,648,087 55,876,180 1,066,669,258 435,843,881 

2004 788,838,770 258,702,396 328,911,083 105,832,798 21,404,013 35,008,826 56,412,839 1,047,541,166 434,743,881 

2005 773,630,411 253,606,743 327,811,083 105,832,798 21,404,013 34,330,266 55,734,279 1,027,237,154 433,643,881 

2006 758,122,052 248,511,090 327,011,083 105,832,798 21,404,013 33,641,680 55,045,693 1,006,633,142 432,843,881 

2007 742,613,692 243,415,436 326,211,083 105,832,798 21,404,012 32,953,093 54,357,105 986,029,128 432,043,881 

2008 727,105,333 238,319,783 325,411,083 105,832,798 25,167,480 32,264,507 57,431,987 965,425,116 431,243,881 

2009 707,833,506 233,224,130 324,611,083 105,832,798 25,167,479 31,450,146 56,617,625 941,057,636 430,443,881 

2010 688,561,680 228,128,477 323,811,083 105,832,798 25,167,481 30,635,785 55,803,266 916,690,157 429,643,881 

2011 669,289,853 223,032,823 323,011,083 105,832,798 26,343,400 29,821,424 56,164,824 892,322,676 428,843,881 

2012 650,018,026 216,761,250 322,211,083 105,832,798 26,343,400 28,967,763 55,311,163 866,779,276 428,043,881 

2013 630,746,199 210,489,677 321,411,083 105,832,798 26,343,399 28,114,103 54,457,502 841,235,876 427,243,881 

2014 611,474,373 204,218,104 320,611,083 105,832,798 26,343,401 27,260,443 53,603,844 815,692,477 426,443,881 

2015 592,202,546 197,946,530 319,811,083 105,832,798 31,361,357 26,406,782 57,768,139 790,149,076 425,643,881 

2016 567,912,762 191,674,957 319,011,083 105,832,798 31,361,356 25,385,422 56,746,778 759,587,719 424,843,881 

2017 543,622,979 185,403,384 318,211,083 105,832,798 31,361,356 24,364,061 55,725,417 729,026,363 424,043,881 

2018 519,333,196 179,131,811 317,411,083 105,832,798 32,929,250 23,342,701 56,271,951 698,465,007 423,243,881 

2019 494,843,412 171,292,344 316,811,083 105,832,798 32,929,249 22,262,257 55,191,506 666,135,756 422,643,881 

2020 470,353,629 163,452,878 316,211,083 105,832,798 32,929,250 21,181,813 54,111,063 633,806,507 422,043,881 

2021 445,863,845 155,613,411 315,611,083 105,832,798 32,929,250 20,101,370 53,030,620 601,477,256 421,443,881 

2022 421,374,062 147,773,944 315,011,083 105,832,798 40,456,185 19,020,926 59,477,111 569,148,006 420,843,881 

2023 389,357,343 139,934,478 314,411,083 105,832,798 40,456,185 17,688,933 58,145,118 529,291,821 420,243,881 

2024 357,340,625 132,095,011 313,811,083 105,832,798 40,456,185 16,356,939 56,813,124 489,435,636 419,643,881 

2025 325,323,906 124,255,545 313,211,083 105,832,798 42,808,025 15,024,945 57,832,970 449,579,451 419,043,881 

2026 293,157,188 114,064,238 312,761,083 105,832,798 42,808,025 13,609,340 56,417,365 407,221,426 418,593,881 

2027 260,990,469 103,872,932 312,311,083 105,832,798 42,808,025 12,193,735 55,001,760 364,863,401 418,143,881 

2028 228,823,751 93,681,625 311,861,083 105,832,798 42,808,025 10,778,130 53,586,155 322,505,376 417,693,881 

2029 196,657,032 83,490,319 311,411,083 105,832,798 44,062,514 9,362,524 53,425,038 280,147,351 417,243,881 

2030 163,235,825 73,299,012 310,961,083 105,832,798 44,062,514 7,904,994 51,967,508 236,534,837 416,793,881 

2031 129,814,617 63,107,706 310,511,083 105,832,798 44,062,514 6,447,464 50,509,978 192,922,323 416,343,881 

2032 96,393,409 52,916,399 310,061,083 105,832,798 44,454,487 4,989,934 49,444,421 149,309,808 415,893,881 

2033 62,951,402 42,333,119 309,631,883 105,832,798 44,454,487 3,518,609 47,973,096 105,284,521 415,464,681 

2034 29,488,594 31,749,840 309,223,483 105,832,798 44,454,488 2,046,588 46,501,076 61,238,434 415,056,281 

2035 - 21,166,560 304,840,869 105,832,798 44,454,488 707,386 45,161,874 21,166,560 410,673,667 

2036 - 10,583,280 270,969,661 105,832,798 44,454,487 353,693 44,808,180 10,583,280 376,802,459 

2037 - - 237,098,454 105,832,798 44,454,487 - 44,454,487 - 342,931,252 

2038 - - 203,227,246 95,249,519 44,454,488 - 44,454,488 - 298,476,765 

2039 - - 169,356,038 84,666,239 44,454,487 - 44,454,487 - 254,022,277 

2040 - - 135,484,831 74,082,959 44,454,488 - 44,454,488 - 209,567,790 

2041 - - 101,613,623 63,499,679 44,454,488 - 44,454,488 - 165,113,302 

2042 - - 67,742,415 52,916,399 44,454,487 - 44,454,487 - 120,658,814 

2043 - - 33,871,208 42,333,119 44,454,487 - 44,454,487 - 76,204,327 

2044 - - - 31,749,840 10,583,280 - 10,583,280 - 31,749,840 

2045 - - - 21,166,560 10,583,280 - 10,583,280 - 21,166,560 

2046 - - - 10,583,280 10,583,280 - 10,583,280 - 10,583,280 

 6,957,918,536 22,958,297,071 14,721,539,734 4,815,392,312 1,646,462,500 971,347,529 2,617,810,029

Payment Due Balance

Beginning Balance Beginning Balance

Interest Bearing Non-Interest Bearing