Pacific Gas & Electric (PCG+A) 8-K Other events

	Exhibit 2
	EXHIBIT C TO THE DISCLOSURE STATEMENT
Assumptions – Nature and Limitations of Projections
The financial projections included in the Disclosure Statement depend upon the successful implementation of the Plan of Reorganization for the Reorganized Debtor, and the validity of the other assumptions contained therein.  These projections reflect numerous assumptions, including confirmation and consummation of the Plan in accordance with its terms, continued access by the Reorganized Debtor to capital markets, the continued availability of the working capital facilities contemplated by the Disclosure Statement, the anticipated future performance of the Reorganized Debtor, certain assumptions with respect to its competitors, general business and economic conditions and other matters, many of which are beyond the control of the Reorganized Debtor.  In addition, the risk factors outlined in the Disclosure Statement and unanticipated events and circumstances occurring subsequent to the preparation of the projections may affect the actual financial results of the Reorganized Debtor.  Although the Proponents believe that the projections are reasonably attainable, variations between the actual financial results and those projected may occur and may be material.
Significant Assumptions Regarding Plan Consummation
The Debtor is assuming that the Plan shall be confirmed by the Bankruptcy Court for the purposes of these projections.  The assumption of Plan confirmation incorporates the following significant assumptions:
the holders of claims in Classes 3a, 3b, 4a, 4c, 4e, 5, 6, and 7 shall have voted to accept the Plan by the requisite statutory majority or majorities as provided in section 1126(c) of the Bankruptcy Code or, if any such class does not accept the Plan, the Bankruptcy Court shall confirm the Plan under section 1129(b) of the Bankruptcy Code;
no material adverse effect on the business, assets, operations, property, or condition (financial or otherwise) of the Debtor or any of its subsidiaries (other than inactive subsidiaries) shall have occurred and be continuing;
no material unanticipated claims shall have been filed or asserted in the Chapter 11 Case;
all necessary regulatory and governmental approvals shall have been received within the contemplated timeline;
all financing transactions contemplated by the Plan shall have been consummated on the terms contemplated by the Plan and the Disclosure Statement; and
the Bankruptcy Court shall have issued the Confirmation Order.
Significant Assumptions Regarding the Pre-Consummation Projections
Cash Balance At December 31, 2003
The Debtor expects to have cash available to reimburse creditors at year-end 2003 of approximately $2.5 billion.  This amount is estimated based on the current cash balances, and taking into account various cash impacts through 2003.  These impacts include reductions for restricted funds, outstanding checks and all operating receipts and disbursements.  Capital expenditures included in the forecast total $1.7 billion in 2003.
Earnings For 2003
Earnings during 2003 reflect both earnings from ongoing utility operations, as well as non-recurring items (including those described as "items affecting comparability") in the Reorganized Debtor's public filings with the Securities and Exchange Commission).  Starting common equity balances in 2004 incorporate these earnings.
Significant Assumptions Regarding Effective Date Funding of Claims
As described in detail in the Plan and Disclosure Statement, claims are funded with a combination of cash on hand, reinstatement of certain financial claims such as preferred stock interests and pollution control bonds in classes 4a, 4b, and 4d, and the cash proceeds of new money notes.  The Reorganized Debtor may also draw on a portion of its proposed bank facilities to fund claims, depending upon its seasonal working capital requirements at the actual effective date.
Claims in Classes 6 and 7 have not been reduced for the impact of any refunds ordered by the Federal Energy Regulatory Commission (FERC) or settlements of disputed claims.   Because the financial projections assume full payment of Class 6 and 7 claims, the levels of debt at the effective date, the size of the Settlement Regulatory Asset, and customer revenues associated with the Settlement Regulatory Asset have not been adjusted for any potential reductions in these claims.
Structure of the Reorganized Debtor
The Reorganized Debtor will remain an integrated electric and gas utility company serving predominantly retail customers in Northern and Central California.  The Reorganized Debtor will retain its existing gas and electric distribution, transmission and customer service assets.
The Reorganized Debtor will provide distribution customer services and revenue cycle services, and will provide and administer public purpose programs for retail electric and gas customers.
The Reorganized Debtor will retain the obligation to procure gas on behalf of its core gas customers and the obligation to procure power on behalf of its retail electric customers.
The Reorganized Debtor will assume and retain the bilateral energy purchase agreements with (a) third party gas suppliers, and (b) QFs and other third party power suppliers, including the Irrigation Districts.
The Reorganized Debtor will retain its electric generation assets, including the 2,174 MW capacity Diablo Canyon nuclear plant, its conventional and pumped storage hydro-electric generating facilities with an aggregate capacity of 3,896 MW, and two small fossil generating facilities.
The Reorganized Debtor will remain subject to rate regulation of the California Public Utilities Commission (CPUC) for its electric distribution, generation and procurement operations, and for its gas distribution, procurement, transmission and storage operations, subject to the terms of the Settlement as incorporated into the Plan and Confirmation Order.
The Reorganized Debtor's high voltage electric transmission assets will provide services for its own retail customers as well as wholesale market participants, both under the jurisdiction of the FERC.
Income Statement
Total Operating Revenues
Revenues include customer payments for electric and gas distribution services, electric transmission and gas transmission and storage services, electric and gas energy procurement purchases (excluding California Department of Water Resources sources of electricity), electric power generated by the Reorganized Debtor's retained electric generating facilities, public purpose programs, recovery of the proposed Settlement Regulatory Asset with associated taxes and return, and Rate Reduction Bonds.
Electric and Gas Revenues include base revenues from the 2003 General Rate Case and subsequent annual attrition proceedings intended to enable the Reorganized Debtor to recover increased costs due to inflation, customer growth and ratebase growth.  The authorized rate of return on common equity (ROE) remains at 11.22%.  The authorized common equity ratio equals 48.6% in 2004, and increases to 52.0% by 2006.  Electric annual load growth for bundled sales approximates 1.4%/year, and gas annual load growth for core customers approximates 1.0%/year.  Electric Direct Access retail load approximates 9,000 GWh annually (11.4% of total deliveries in 2004) and is held constant throughout the forecast period.
Electric Revenues also include base revenues to enable the Reorganized Debtor to recover non-fuel operating costs, depreciation, taxes and rate of return on its retained electric generation assets, as well as revenues to recover amortization, return, and associated taxes on the Settlement Regulatory Asset.
Electric and gas procurement revenues match electric and gas procurement expenses.  Excluded are revenues collected for electric energy procured by DWR on behalf of the Reorganized Debtor's customers.  Cash revenues (receipts) lag expenses (disbursements) by the average working capital lag of 16 days.
Electric and Gas Public Purpose Program Revenue, excluding CARE, total $310 million in 2004 and escalate thereafter. Identical M&O expenses offset these revenues so there is no impact on earnings or cash from operations.
Operating Expenses
Total Cost of Energy includes all electric and gas commodity procured on behalf of retail electric and gas customers by the Reorganized Debtor.  Electric commodity costs include QF contracts, natural gas fuel for the Hunters Point and Humboldt power plants, nuclear fuel for the Diablo Canyon power plant, Irrigation District contracts, and other commodity procurement and grid management expenses.  Excluded are remittances to DWR for power it procures on behalf of the Reorganized Debtor's customers and for bond debt service.
M&O and A&G Costs include direct M&O Expenses for electric and gas distribution, transmission, and the Reorganized Debtor's retained generating assets, A&G costs, public purpose programs and franchise and uncollectibles expenses.
Depreciation is calculated for distribution and electric generation assets using depreciation rates proposed in the Reorganized Debtor's current 2003 Test Year CPUC General Rate Case (GRC).  Electric and gas transmission depreciation reflects depreciation rates used to develop tariffs currently authorized by the FERC and CPUC, respectively.   Depreciation expense also includes amortization of the Settlement regulatory asset including its provision for taxes on recovery of principal.   Other items included in depreciation include provisions for fossil and nuclear power plant decommissioning.
Property Tax is estimated at about 1% of net plant.  Franchise Fees and Uncollectable expenses are estimated at about 1% of revenue.
Interest Expense
Interest Expense (excluding Rate Reduction Bonds) consists mainly of interest on long-term debt.  Interest expense is based on interest rates of approximately 6.5% for new debt and 4.5% for reinstated Pollution Control bonds.  Borrowing costs are based on the all-in, effective costs to the Reorganized Debtor.  Corresponding debt balances are net of issuance expenses.  Accordingly, the par value of debt issued will be approximately 1.0 percent higher than the net balances shown.   Rate Reduction Bond interest and the amortization of the net gain or loss on reacquired debt are shown separately.
Other Income
Other Income is comprised of "below-the-line" income and expenses, including AFUDC, operating costs not recoverable in retail rates, and non-recurring items.
Income Taxes
Income Taxes are calculated using a 35% federal tax rate and an 8.84% state tax rate, with a combined tax rate of 40.746%.  The book income tax provision reflects existing regulatory practices for recognizing the timing of income tax expenses.
Dividends
Preferred Dividend arrearages are paid on the Effective Date.  Preferred dividends are based on an embedded cost of preferred stock of approximately 6.5%.
Balance Sheet
Assets
Generally, balances of assets and liabilities are either held constant at their starting level, or are taken as a percentage of a revenue or expense.  Plant in service, construction work in progress, common stock and long-term debt are dynamic balances, changing as a function of cash from operations and capital expenditures.  Net plant includes the value of the Reorganized Debtor's retained generation facilities under cost of service regulation per Advice Letter 2233-E implementing D.02-04-016, as per the Settlement, Plan and Confirmation Order and as expected to be further modified through normal depreciation, additions, and retirements.  Cash balances are held constant at an initial level for restricted funds and check float.
Capitalization
Short-term debt is used to fund seasonal working capital requirements and natural gas storage inventory.  Any subsequent surplus cash is used for debt retirement or distribution to common shareholders in amounts necessary to achieve and then maintain the target capital structure.  For the Reorganized Debtor, the targeted common equity to total long-term capitalization ratio is 52% (excluding rate reduction bonds and short-term debt used to finance seasonal working capital requirements or natural gas storage inventory).
Cash Flow Statement
Cash from operations is estimated by adding back depreciation and deferred taxes to net income, plus changes in working capital.  Seasonal variations in receipts and reimbursements will cause these average requirements to fluctuate within a range of approximately +/- $300 million.
Subsequent to the Effective Date, the Reorganized Debtor manages its capital structure such that it achieves an overall ratio of common equity to total capitalization of 52% within two years, and then maintains that common equity ratio over time.  Reorganized Debtor commences cash distributions to common shareholders (shown as common stock repurchases) when it reaches its target capital structure in the second half of 2005.  Subsequently, Reorganized Debtor issues or repurchases debt and common equity annually in order to maintain this capital structure.

REORGANIZED DEBTOR
	12/31/2003	12/31/2004	12/31/2005	12/31/2006	12/31/2007	12/31/2008
	($Millions)
INCOME STATEMENT
Total Operating Revenues*…………………	0.0	10554.6	10780.1	10813.5	11056.2	11178.3
Operating Expenses
Total Cost of Energy*……………………….	0.0	3296.4	3322.0	3176.6	3228.0	3458.0
M&O and A&G Costs………………….…....	0.0	3119.1	3154.9	3201.0	3279.7	3354.2
Depreciation & Decommissioning………….	0.0	1429.1	1512.1	1578.8	1683.2	1788.5
Property & Other Taxes………………..……	0.0	166.8	172.7	177.0	179.7	181.4
RRB Asset Amortization…………………..	0.0	290.2	289.7	289.7	289.7	(0.4)
Total Operating Expenses………….…..…..	0.0	8301.5	8451.4	8423.0	8660.3	8781.7
Operating Income……………………………	0.0	2253.1	2328.7	2390.5	2395.8	2396.6
Total Interest Income………………………..	0.0	13.0	13.0	13.0	13.0	13.0
Interest Expense (Excl RRBs)…………………	0.0	574.4	554.6	552.3	558.7	561.9
Amortization of Loss on Reacquired Debt		24.6	24.6	24.6	24.6	24.6
RRB Interest…………………………..………..	0.0	68.9	50.3	31.5	12.1	0.0
Total Interest Expense……….………………..	0.0	667.9	629.5	608.4	595.4	586.5
Other Income…………………….……………..	0.0	(6.7)	(7.9)	(13.5)	(14.6)	(14.7)
Pretax Income……………….…………………..	0.0	1591.5	1704.3	1781.6	1798.9	1808.4
Total Booked Income Taxes…………………..	0.0	678.4	722.2	757.1	765.3	772.0
Preferred Dividend Req……………….……….	0.0	24.7	24.2	23.2	23.5	24.5
Total Earnings Avail for Common…….………	0.0	888.3	957.9	1001.2	1010.2	1011.9
___________________
* Excludes Receipts and Disbursements for CDWR Procurement.
	12/31/2003	12/31/2004	12/31/2005	12/31/2006	12/31/2007	12/31/2008
	($Millions)
BALANCE SHEET
Assets
Plant in Service………………………..……….	28965.8	30405.9	32014.5	33289.9	34653.0	36043.7
Accumulated Depr………………………….….	(13142.6)	(14064.7)	(14992.4)	(15920.4)	(16904.0)	(17938.0)
Net Plant…………………………………….….	15823.2	16341.3	17022.1	17369.4	17749.0	18105.7
Construction Work In Progress…….……….	318.3	359.0	292.1	291.4	291.0	306.9
Nuclear Decommissioning Trust Fund	1376.0	1406.6	1437.3	1467.9	1498.6	1529.2
Other Noncurrent Assets………………….…	65.1	65.1	65.1	65.1	65.1	65.1
Total Long-term Assets………………..…….	17582.6	18172.1	18816.6	19193.9	19603.7	20007.0
Current Assets:
Short-term Investments (Net) ……………..…	433.0	433.0	433.0	433.0	433.0	433.0
Accounts Receivable…………………….……	1671.0	1668.3	1691.9	1686.3	1721.0	1741.5
Balancing Accts Receivable …………………	85.4	85.4	85.5	85.6	85.6	85.7
Inventory - Fuels …..………………………….	358.8	391.8	381.1	352.9	343.6	355.2
Inventory - M&S ...…………………………….	127.7	129.5	131.2	132.9	134.6	136.3
Prepayments & Adv to Gas Prod……………	80.7	80.7	80.7	80.7	80.7	80.7
Total Current Assets…………………….….	2756.6	2788.7	2803.3	2771.3	2798.5	2832.3
Deferred Charges:
Expense Deferral (Regulatory Asset)	1241.8	951.6	662.0	372.4	82.7	83.2
Regulatory Assets…………………………….	2210.0	2068.1	1907.4	1725.4	1519.3	1286.0
URG Regulatory Assets……………………...	793.0	747.5	702.0	656.5	611.0	565.5
Regulatory Assets Def Tax……………..……	2065.0	1936.1	1794.4	1637.9	1464.9	1273.2
Other Deferred Charges……………………….	1750.9	1719.5	1688.1	1656.7	1625.3	1593.9
Total Deferred Charges…….……………….	8060.7	7422.9	6753.8	6048.8	5303.2	4801.7
TOTAL ASSETS…………………..………….	28399.9	28383.6	28373.8	28014.0	27705.4	27641.1
	12/31/2003	12/31/2004	12/31/2005	12/31/2006	12/31/2007	12/31/2008
	($Millions)
Capitalization:
Common Stock Equity…………..…………….	7971.4	8859.8	9512.0	9591.7	9683.0	9689.6
Preferred Stock (incl QUIDS)……..………….	416.0	412.9	406.0	399.1	424.7	421.6
RRBs Outstanding…………………………….	1160.3	870.2	580.1	290.0	0.0	0.0
Other Long-term Debt……………..………….	8841.2	8799.0	8374.0	8454.4	8513.3	8522.4
Total Capitalization…………………….….….	18389.0	18941.8	18872.1	18735.1	18621.0	18633.6
Current Liabilities:
Short-Term Borrowings ..……………….…….	500.0	(0.0)	215.2	198.1	198.8	219.3
Accounts Payable - Creditors ..……….…….	859.2	841.5	843.1	825.9	840.9	874.4
Accounts Payable - Affiliates ..…………….	0.0	0.0	0.0	0.0	0.0	0.0
Balancing Accounts Payable ……………….	141.2	140.2	139.3	138.4	137.6	136.7
Accrued Taxes Payable …………….……….	325.6	344.7	360.0	363.8	367.0	357.3
Interest Payable ……………………..……….	17.9	35.1	49.1	48.2	48.8	49.1
Dividends Payable ………………….……….	0.0	0.0	0.0	0.0	0.0	0.0
Other Current Liabilities………………..……	577.7	577.7	577.7	577.7	577.7	577.7
Total Current Liabilities ……………….……	2421.6	1939.1	2184.4	2152.1	2170.8	2214.6
Deferred Credits and Other NC Liabilities:
Deferred Income Taxes…………….………….	3240.5	3137.3	2924.6	2708.2	2467.3	2320.9
Deferred ITC…………………………..……….	140.9	134.7	128.5	122.3	116.1	109.9
Noncurrent Balancing Acct Liab…………….	0.0	0.0	0.0	0.0	0.0	0.0
Customer Advances for Construction…….	132.0	123.9	126.8	128.3	131.7	133.0
Other Deferred Credits………………..…….	1787.8	1787.8	1787.8	1787.8	1787.8	1787.8
Other Noncurrent Liab.………………….….	2288.1	2318.9	2349.6	2380.2	2410.7	2441.4
Total Deferred Credits & NC Liab…………	7589.4	7502.7	7317.3	7126.8	6913.6	6792.9
TOTAL CAPITAL & LIABILITIES………….	28399.9	28383.6	28373.8	28014.0	27705.4	27641.1
	12/31/2003	12/31/2004	12/31/2005	12/31/2006	12/31/2007	12/31/2008
	($Millions)
CASH FLOW STATEMENT
Cash Flows From Operations:
Net Income………………………………….….	0.0	913.1	982.1	1024.4	1033.7	1036.4
Depreciation…………………………..……….	0.0	1423.1	1506.1	1572.7	1677.2	1782.4
Change in Deferred Taxes…………………….	0.0	(109.4)	(218.9)	(222.6)	(247.2)	(152.6)
Change in Accts Receivable………………….	0.0	2.8	(23.7)	5.7	(34.8)	(20.5)
Change in Inventories…………………..…….	0.0	(34.8)	9.1	26.4	7.6	(13.3)
Change in Accts Payable…………………….	0.0	(17.7)	1.6	(17.2)	15.0	33.5
Change in Accrued Taxes Payable………….	0.0	19.1	15.3	3.8	3.2	(9.7)
Change in Bal Accts & Reg Asset Amort….	0.0	289.2	288.7	288.7	288.7	(1.4)
Change in Other Working Capital……….….	0.0	13.0	14.0	(0.9)	0.5	0.4
Other Net Cash from Operations…………….	0.0	83.1	99.4	97.0	93.0	95.1
Net Cash from Operations……………………	0.0	2581.4	2673.7	2778.2	2837.1	2750.3
Investing Activities:
Capital Expenditures……………………….….	0.0	(1694.8)	(1806.4)	(1568.8)	(1659.3)	(1716.5)
Other Net Investing Activities……………….	0.0	(30.6)	(30.6)	(30.6)	(30.6)	(30.6)
Net Cash Used In Investing………….………	0.0	(1725.4)	(1837.1)	(1599.4)	(1689.9)	(1747.2)
Financing Activities:
Common Stock Issued (Repurchased) ..…..…	0.0	0.0	(305.6)	(921.6)	(918.8)	(1005.3)
Preferred Stock Issued………………………...	0.0	0.0	0.0	0.0	85.0	0.0
Preferred Stock redeemed……………….…….	0.0	(3.1)	(6.9)	(6.9)	(59.4)	(3.1)
Long-term Debt issued…………..……………	0.0	(42.1)	(425.0)	80.3	58.9	9.1
Long-term Debt matured/redeemed………….	0.0	0.0	0.0	0.0	0.0	0.0
Long-term Debt purch/sinking……………….	0.0	0.0	0.0	0.0	0.0	0.0
RRB Principal Repayments……………..…….	0.0	(290.1)	(290.1)	(290.1)	(290.1)	0.0
Change in Short-term Position……………….	0.0	(500.0)	215.2	(17.1)	0.7	20.5
Dividends Disbursed………………………….	0.0	(20.6)	(24.3)	(23.4)	(23.5)	(24.4)
Other Net Financing Activities……………….	0.0	0.0	0.0	0.0	0.0	0.0
Net Cash Used In Financing………………….	0.0	(856.0)	(836.7)	(1178.7)	(1147.1)	(1003.2)
Net Change in Cash……………………….….	0.0	(0.0)	0.0	0.0	0.0	0.0
	12/31/2003	12/31/2004	12/31/2005	12/31/2006	12/31/2007	12/31/2008
	($Millions)
SUPPLEMENTAL INFORMATION
Revenues
Gas………………………………………….…………….		2532.2	2611.6	2540.9	2650.1	2863.2
Public Purpose………………………………………….		313.4	322.4	331.5	341.0	350.7
Electric…………………………………………………..		7708.9	7846.2	7941.0	8065.1	7964.4
Total from Inc Stmt……………………………………….		10554.6	10780.1	10813.5	11056.2	11178.3
Energy Costs
Gas Procurement……………………………………….		1052.3	1067.4	939.5	1006.1	1181.8
Nuclear Fuel + Hydro Water + ID Payments……..…		140.0	144.0	145.0	147.0	148.0
QF Payments………………………………………..….		1560.6	1546.3	1466.3	1342.1	1322.5
Third Party Bilats………………………………………		0.0	0.0	0.0	0.0	0.0
Net Open……………………………………………..…		349.0	291.2	337.1	401.8	434.9
Other Gen Costs1……………………………………….		194.5	273.1	288.7	331.0	370.8
Total from Inc Stmt……………………………………..		3296.4	3322.0	3176.6	3228.0	3458.0
M&O and A&G Costs
Gas……………………….……………………………….		702.5	724.2	741.5	764.5	784.1
Public Purpose………………………………………….		310.2	319.0	328.1	337.5	347.1
Electric…………………………………………………..		2106.3	2111.6	2131.4	2177.8	2223.0
Total from Inc Stmt…………………………………….		3119.1	3154.9	3201.0	3279.7	3354.2
Depreciation & Decommissioning
Gas……………………………………………………….		282.7	296.4	311.0	327.2	339.6
Electric2………………………………………………….		1171.0	1240.3	1292.3	1380.6	1473.5
Total from Inc Stmt…………….………………………		1453.7	1536.7	1603.4	1707.8	1813.1
Property & Other Taxes
Gas………………………………………………………..		39.0	40.1	41.4	42.1	42.3
Electric……………………………………………………		127.8	132.7	135.5	137.6	139.1
Total from Inc Stmt…………………………………….		166.8	172.7	177.0	179.7	181.4
Average Annual Rate Base
Gas………………………………………………………		3650.1	3784.6	3903.5	3911.1	3940.7
Electric…………………………………………………..		10358.0	10717.1	11044.2	11307.3	11546.0
URG Regulatory Asset………….……………………		770.3	724.8	679.3	633.8	588.3
Settlement Regulatory Asset………………………….		2139.1	1987.8	1816.4	1622.4	1402.7
Authorized Capital Structure
% Debt………………………………………………….		49.1%	47.3%	45.8%	45.7%	45.7%
% Preferred…………………………………………….		2.3%	2.2%	2.2%	2.3%	2.3%
% Equity……………………………………………….		48.6%	50.5%	52.0%	52.0%	52.0%
		100.0%	100.0%	100.0%	100.0%	100.0%
Authorized Cost of Capital
Debt*…………………………………………………….		6.25%	6.28%	6.31%	6.34%	6.34%
Preferred*………………………………………….…….		6.50%	6.50%	6.50%	6.50%	6.50%
Equity…………………………………………………….		11.20%	11.20%	11.20%	11.20%	11.20%
Return on Rate Base…………………………………….		8.66%	8.77%	8.86%	8.87%	8.87%
______________
1Includes ISO and Retained Fossil fuel costs net of RMR revenues and WAPA payments
2Includes URG and Settlement Regulatory Asset Amortization
*Excludes refunding costs recovered through authorized cost of debt
SUPPLEMENTAL INFORMATION
Gas Procurement Volumes and Average Price
Gas Sales (mDTH)………………………………………...		289,964	293,022	295,963	299,030	302,121
Average Price ($/mmBtu)……………………………….		3.63	3.64	3.17	3.36	3.91
Elec Procurement Volumes and Average Price1
Volumes (GWh)
Hydro/Helms/Diablo/ID………………………………		33,114	33,514	33,514	33,530	33,530
QF………………………………………………….……		21,004	20,758	20,312	19,553	19,044
Other Gen2…………………………………………...…		2,518	3,141	3,517	3,839	4,584
Net Open…………………………………………….…		2,878	1,464	1,923	1,867	2,532
Total Non-DWR Supply………………………………		59,514	58,877	59,266	58,789	59,690
DWR……………………………………………………		19,191	18,621	19,279	20,252	19,959
Total (excl D/A)……………………………………..……		78,704	77,498	78,546	79,042	79,649
Average Price ($/MWh)
QF………………………………………………………		74.30	74.49	72.19	68.64	69.44
Other Gen3……………………………………………..		77.26	86.94	82.08	86.22	80.90
Net Open………………………………………………		121.26	198.95	175.34	215.24	171.77
Total Non-DWR Supply………………………………		79.70	83.22	81.24	82.14	81.35
DWR……………………………………………………		110.26	111.22	103.47	99.58	102.73
Overall Average (excl D/A)………………………..……		92.57	95.07	90.76	89.90	90.61
Sales/Deliveries (GWh)
Total Deliveries……………………………………..……		78,686	79,686	80,688	81,690	82,684
Bundled Sales…………………………………………		69,721	70,721	71,723	72,725	73,719
Direct Access…………………………………………		8,965	8,965	8,965	8,965	8,965
Average Rate (½/kWh)
Total Deliveries………………………………….……		12.58	12.55	12.41	12.45	12.22
Bundled Sales…………………………………………		13.36	13.32	13.16	13.18	12.92
Direct Access…………………………………………		6.45	6.45	6.45	6.45	6.45
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1Electric Procurement Volumes and Average Prices are shown before the effects of netting line losses and Helms pumping
2Includes Retained Fossil, Etiwanda & EBMUD, and Puget inbound
3Includes ISO Ancillary Services, Renewables, and Retained Fossil fuel costs net of RMR revenues and WAPA payments