REPUBLIC SERVICES, INC.  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED approximately $32 million of federal tax payments were deferred and paid in 2009 as a result of the Allied acquisition.
The following table summarizes the activity in our gross unrecognized tax benefits for the years ended December 31:
## Table 0 ##
New accounting guidance for business combinations became effective for our 2009 financial statements.
This new guidance changed the treatment of acquired uncertain tax liabilities.
Under previous guidance, changes in acquired uncertain tax liabilities were recognized through goodwill.
Under the new guidance, subsequent changes in acquired unrecognized tax liabilities are recognized through the income tax provision.
As of December 31, 2010, $206.5 million of the $222.8 million of unrecognized tax benefits related to tax positions taken by Allied prior to the 2008 acquisition.
Included in the balance at December 31, 2010 and 2009 are approximately $209.1 million and $217.6 million of unrecognized tax benefits (net of the federal benefit on state issues) that, if recognized, would affect the effective income tax rate in future periods.
During 2010, the IRS concluded its examination of our 2005 and 2007 tax years.
The conclusion of this examination reduced our gross unrecognized tax benefits by approximately $1.9 million.
We also resolved various state matters during 2010 that, in the aggregate, reduced our gross unrecognized tax benefits by approximately $10.0 million.
During 2009, we settled our outstanding tax dispute related to Allied’s risk management companies (see – Risk Management Companies) with both the Department of Justice (DOJ) and the Internal Revenue Service (IRS).
This settlement reduced our gross unrecognized tax benefits by approximately $299.6 million.
During 2009, we also settled with the IRS, through an accounting method change, our outstanding tax dispute related to intercompany insurance premiums paid to Allied’s captive insurance company.
This settlement reduced our gross unrecognized tax benefits by approximately $62.6 million.
In addition to these federal matters, we also resolved various state matters that, in the aggregate, reduced our gross unrecognized tax benefits during 2009 by approximately $5.8 million.
We recognize interest and penalties as incurred within the provision for income taxes in our consolidated statements of income.
Related to the unrecognized tax benefits previously noted, we accrued interest of $19.2 million during 2010 and, in total as of December 31, 2010, have recognized a liability for penalties of $1.2 million and interest of $99.9 million.
During 2009, we accrued interest of $24.5 million and, in total at December 31, 2009, had recognized a liability for penalties of $1.5 million and interest of $92.3 million.
During 2008, we accrued penalties of $0.2 million and interest of $5.2 million and, in total at December 31, 2008, had recognized a liability for penalties of $88.1 million and interest of $180.0 million.
NONREGULATED OPERATING MARGINS The following table details the changes in nonregulated revenue and margin included in continuing operations:
## Table 1 ##
2004 Comparison to 2003 Nonregulated revenue decreased in 2004, due primarily to the discontinued consolidation of an investment in an independent power-producing entity that was no longer majority owned.
NON-FUEL OPERATING EXPENSES AND OTHER ITEMS Other Utility Operating and Maintenance Expenses Other operating and maintenance expenses for 2005 increased by approximately $87 million, or 5.5 percent, compared with 2004.
An outage at the Monticello nuclear plant and higher outage costs at Prairie Island in 2005 increased costs by approximately $26 million.
Employee benefit costs were higher in 2005, primarily due to increased pension benefits and long-term disability costs.
Also contributing to the increase were higher uncollectible receivable costs, attributable in part to modifications to the bankruptcy laws, higher fuel prices and certain changes in the credit and collections process.
Other operating and maintenance expenses for 2004 increased by approximately $21 million, or 1.4 percent, compared with 2003.
Of the increase, $12 million was incurred to assist with the storm damage repair in Florida and was offset by increased revenue.
The remaining increase of $9 million is primarily due to higher electric service reliability costs, higher information technology costs, higher plant-related costs, higher costs related to a customer billing system conversion and increased costs primarily related to compliance with the Sarbanes-Oxley Act of 2002.
The higher costs were partially offset by lower employee benefit and compensation costs and lower nuclear plant outage costs
## Table 2 ##
Other Nonregulated Operating and Maintenance Expenses Other nonregulated operating and maintenance expenses decreased $16 million, or 35.4 percent, in 2005 compared with 2004, primarily due to the accrual of $18 million in 2004 for a settlement agreement related to shareholder lawsuits.
Other nonregulated operating and maintenance expenses decreased $9 million, or 17.5 percent, in 2004 compared with 2003.
This decrease resulted from the dissolution of Planergy International and the discontinued consolidation of an investment in an independent powerproducing entity that was no longer majority owned after the divestiture of NRG.
Depreciation and Amortization Depreciation and amortization expense for 2005 increased by approximately $61 million, or 8.7 percent, compared with 2004.
The changes were primarily due to the installation of new steam generators at Unit 1 of the Prairie Island nuclear plant and software system additions, both of which have relatively short depreciable lives compared with other capital additions.
The Prairie Island steam generators are being depreciated over the remaining life of the plant operating license, which expires in 2013.
In addition, the Minnesota Renewable Development Fund and renewable cost-recovery amortization, which is recovered in revenue as a non-fuel rider and does not have an impact on net income, increased over 2004.
The increase was partially offset by the changes in useful lives and net salvage rates approved by Minnesota regulators in August 2005.
Depreciation and amortization expense for 2004 decreased by $21 million, or 2.9 percent, compared with 2003.
The reduction is largely due to several regulatory decisions.
In 2004, as a result of a Minnesota Public Utilities Commission (MPUC) order, NSP-Minnesota modified its decommissioning expense recognition, which served to reduce decommissioning accruals by approximately $18 million in 2004 compared with 2003.
In addition, effective July 1, 2003, the Colorado Public Utilities Commission (CPUC) lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, reducing annual depreciation expense by $20 million.
PSCo experienced the full impact of the annual reduction in 2004, resulting in a decrease in depreciation expense of $10 million for 2004 compared with 2003.
These decreases were partially offset by plant additions.
Contractual Obligations and Other Commitments — Xcel Energy has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs.
The following is a summarized table of contractual obligations and other commercial commitments at Dec.  31, 2007.
See additional discussion in the consolidated statements of capitalization and Notes 4, 5, and 15 to the consolidated financial statements.
## Table 3 ##
(a) Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date.
Most of Xcel Energy’s railcar, vehicle and equipment and aircraft leases have these terms.
At Dec.  31, 2006, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $176.8 million.
In addition, at the end of the equipment leases’ terms, each lease must be extended, equipment purchased for the greater of the fair value or unamortized value or equipment sold to a third party with Xcel Energy making up any deficiency between the sales price and the unamortized value.
(b) Included in operating lease payments are $76.6 million, $151.7 million, $124.5 million and $916.6 million, for the less than 1 year, 1-3 years, 4-5 years and after 5 years categories, respectively, pertaining to five purchase power agreements that were accounted for as operating leases.
(c) Included in other long-term obligations are tax, penalties and interest related to unrecognized tax benefits recorded according to FIN 48.
(d) Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements.
Additionally, the utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations.
Certain contractual purchase obligations are adjusted based on indices.
The effects of price changes are mitigated through cost-of-energy adjustment mechanisms.
(e) Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to approximately $1.6 billion of goods and services through the year 2050, in addition to the amounts disclosed in this table and in the forecasted capital expenditures.
Xcel Energy has also executed five additional purchase power agreements that are conditional upon achievement of certain conditions, including becoming operational.
Estimated payments under these conditional obligations are $52.8 million, $165.7 million, $177.9 million and $1.7 billion, respectively, for the less than 1 year, 1-3 years, 4-5 years and after 5 years categories.
Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial position, cash flows and other factors, and will be evaluated by the Xcel Energy board of directors.
Xcel Energy’s objective is to increase the annual dividend in the range of 2 percent to 4 percent per year.
Xcel Energy’s dividend policy balances: ?
Projected cash generation from utility operations; ?
Projected capital investment in the utility businesses; ?
A reasonable rate of return on shareholder investment; and ?
The impact on Xcel Energy’s capital structure and credit ratings.
In addition, there are certain statutory limitations that could affect dividend levels.
Federal law places certain limits on the ability of public utilities within a holding company system to declare dividends.
Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account.
The cash to pay dividends to Xcel Energy shareholders is primarily derived from dividends received from its utility subsidiaries.
The utility subsidiaries are generally limited in the amount of dividends allowed by state regulatory commissions to be paid to the holding company.
The limitation is imposed through equity ratio limitations that range from 30 percent to 60 percent.
Some utility subsidiaries must comply with bond indenture covenants or restrictions under credit agreements for debt to total capitalization ratios.
Results of Operations The following table summarizes the diluted EPS for Xcel Energy and subsidiaries:

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2010	2009	2008
Balance at beginning of year	$242.2	$611.9	$23.2
Additions due to the Allied acquisition	-	13.3	582.9
Additions based on tax positions related to current year	2.8	3.9	10.6
Reductions for tax positions related to the current year	-	-	-5.1
Additions for tax positions of prior years	7.5	5.6	2.0
Reductions for tax positions of prior years	-7.4	-24.1	-1.3
Reductions for tax positions resulting from lapse of statute of limitations	-10.4	-0.5	-0.4
Settlements	-11.9	-367.9	-
Balance at end of year	$222.8	$242.2	$611.9

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(Millions of Dollars)	2005	2004	2003
Nonregulated and other revenue	$74	$75	$134
Nonregulated cost of goods sold	-25	-29	-81
Nonregulated margin	$49	$46	$53

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(Millions of Dollars)	2005 vs. 2004	2004 vs. 2003
Higher (lower) employee benefit costs	$31	$-12
Higher (lower) nuclear plant outage costs	26	-13
Higher uncollectible receivable costs	19	2
Higher donations to energy assistance programs	4	1
Higher mutual aid assistance costs	1	12
Higher electric service reliability costs	9	9
Higher (lower) information technology costs	-6	8
Higher (lower) plant-related costs	-7	4
Higher costs related to customer billing system conversion	4	4
Higher costs to comply with Sarbanes-Oxley Act of 2002	—	4
Other	6	2
Total operating and maintenance expense increase	$87	$21

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Payments Due by Period
Total	Less than 1 Year	1 to 3 Years	4 to 5 Years	After 5 Years
(Thousands of Dollars)
Long-term debt, principal and interest payments	$12,599,312	$1,065,530	$1,849,818	$1,760,489	$7,923,475
Capital lease obligations	85,951	6,139	11,794	11,139	56,879
Operating leases(a),(b)	1,439,346	104,557	200,000	161,743	973,046
Unconditional purchase obligations	12,047,364	2,448,155	3,321,234	2,247,977	4,029,998
Other long-term obligations — WYCO investment	121,000	108,000	13,000	—	—
Other long-term obligations(c)	165,847	31,589	42,775	38,964	52,519
Payments to vendors in process	145,059	145,059	—	—	—
Short-term debt	1,088,560	1,088,560	—	—	—
Total contractual cash obligations(d)	$27,692,439	$4,997,589	$5,438,621	$4,220,312	$13,035,917

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Question: what was the percent of the decline in the gross unrecognized tax benefits from 2009 to 2010
Answer: -0.0801