Table XVII Quarterly Reconciliations to GAAP Financial Measures (1)
## Table 0 ##
(1) Presents reconciliations of non-GAAP financial measures to GAAP financial measures.
We believe the use of these non-GAAP financial measures provides additional clarity in assessing the results of the Corporation.
Other companies may define or calculate non-GAAP financial measures differently.
For more information on non-GAAP financial measures and ratios we use in assessing the results of the Corporation, see Supplemental Financial Data on page 32.
Closed or otherwise disposed claims were significantly higher in 2007, compared with 2008, following a review in 2007 of inactive files that revealed that payment was no longer sought on the files, therefore, the files were closed.
The following table shows our gross and net survival ratios for our A&E loss reserves and ALAE reserves at December 31, 2008 and 2007.
## Table 1 ##
The net ratios reflect third party reinsurance other than the aggregate excess reinsurance provided under the NICO contracts.
These survival ratios are calculated by dividing the asbestos or environmental loss and ALAE reserves by the average asbestos or environmental loss and ALAE payments for the three most recent calendar years (3 year survival ratio), and by asbestos or environmental loss and ALAE payments in 2008 (1 year survival ratio).
The survival ratios provide only a very rough depiction of reserves, and are significantly impacted by a number of factors such as aggressive settlement practices, variations in gross to ceded relationships within the asbestos or environmental claims and levels of coverage provided.
We, therefore, urge caution in using these very simplistic ratios to gauge reserve adequacy and note that the 1 year survival ratios, particularly, are likely to move considerably from year to year for the reasons just described.
The 1 year gross survival ratios for both asbestos and environmental decreased markedly from 2007 due to a number of large settlements in 2008.
This has resulted in a decline in the three year gross ratios as well, though to a lesser degree than seen in the 1 year ratios.
The 1 year net asbestos ratio of 18.2 was abnormally high because of the relatively large ceded reinsurance associated with asbestos payments in 2008.
Brandywine run-off entities In addition to housing a significant portion of our A&E exposure, the Brandywine operations include run-off liabilities related to various insurance and reinsurance businesses.
The following companies comprise ACE’s Brandywine operations: Century (a Pennsylvania insurer), Century Re (a Pennsylvania insurer), and Century International Reinsurance Company Ltd.  (a Bermuda insurer (CIRC)).
All of the Brandywine companies are direct or indirect subsidiaries of Brandywine Holdings.
The U. S. -based ACE INA companies assumed two contractual obligations in respect of the Brandywine operations in connection with the Restructuring: a dividend retention fund obligation and a surplus maintenance obligation in the form of an aggregate excess of loss reinsurance agreement.
INA Financial Corporation established and funded a dividend retention fund (the Dividend Retention Fund) consisting of $50 million plus investment earnings.
Pursuant to an interpretation of the Brandywine restructuring order, the full balance of the Dividend Retention Fund was contributed to Century as of December 31, 2002.
Under the Restructuring Order, while any obligation to maintain the Dividend Retention Fund is in effect, to the extent dividends are paid by INA Holdings Corporation to its parent, INA Financial Corporation, and to the extent INA Financial Corporation then pays such dividends to INA Corporation, a portion of those dividends must be withheld to replenish the principal of the Dividend Retention Fund to $50 million within five years.
In 2008, 2007 and 2006, no such dividends were paid and, therefore, no replenishment of the Dividend Retention Fund occurred.
The Dividend Retention Fund may not be terminated without prior written approval from the Pennsylvania Insurance Commissioner.
In addition, an ACE INA insurance subsidiary provided reinsurance coverage to Century in the amount of $800 million under an aggregate excess of loss reinsurance agreement (the Aggregate Excess of Loss Agreement) if the statutory capital and surplus of Century falls below $25 million or if Century lacks liquid assets with which to pay claims as they become due, after giving effect to the contribution of the balance, if any, of the Dividend Retention Fund.
Effective December 31, 2004, ACE INA Holdings contributed $100 million to Century in exchange for a surplus note.
After giving effect to the contribution and issuance of the surplus note, the statutory surplus of Century at December 31, 2008, was $25 million and approximately $112 million in statutory-basis losses have been ceded to the Aggregate Excess of Loss Agreement on an inception-to-date basis.
Century reports the amount ceded under the Aggregate Excess of Loss Agreement in accordance with statutory accounting principles, which differ from GAAP by, among other things, allowing Century to discount its liabilities, including certain asbestos related and environmental pollution liabilities.
The reduction in 2008 in statutory-basis losses ceded to the Aggregate Excess of Loss Agreement resulted principally from the cession of certain reinsurance amounts associated with estimates of reinsurer bad debt, to affiliated ACE companies, and from an increase in discount benefit.
For
4.
SECURITIZATIONS We maintain a revolving securitization program (“warehouse facility”) that currently provides financing of up to $1.2 billion to fund substantially all of the auto loan receivables originated by CAF until they can be funded through a term securitization or alternative funding arrangement.
We sell the auto loan receivables to a wholly owned, bankruptcy-remote, special purpose entity that transfers an undivided interest in the receivables to entities formed by third-party investors (“bank conduits”).
The bank conduits issue asset-backed commercial paper supported by the transferred receivables, and the proceeds from the sale of the commercial paper are used to pay for the securitized receivables.
The return requirements of investors in the bank conduits could fluctuate significantly depending on market conditions.
The warehouse facility has a 364-day term ending in August 2010.
At renewal, the cost, structure and capacity of the facility could change.
These changes could have a significant impact on our funding costs.
The bank conduits may be considered variable interest entities, but are not consolidated because we are not the primary beneficiary and our interest does not constitute a variable interest in the entities.
We hold a variable interest in specified assets transferred to the entities rather than interests in the entities themselves.
Historically, we have used term securitizations to refinance the receivables previously securitized through the warehouse facility.
The purpose of term securitizations is to provide permanent funding for these receivables.
In these transactions, a pool of auto loan receivables is sold to a bankruptcy-remote, special purpose entity that in turn transfers the receivables to a special purpose securitization trust.
The securitization trust issues asset-backed securities, secured or otherwise supported by the transferred receivables, and the proceeds from the sale of the securities are used to pay for the securitized receivables.
Refinancing receivables in a term securitization could have a significant impact on our results of operations depending on the transaction structure and market conditions.
The warehouse facility and each term securitization are governed by various legal documents that limit and specify the activities of the special purpose entities and securitization trusts (collectively, “securitization vehicles”) used to facilitate the securitizations.
The securitization vehicles are generally allowed to acquire the receivables being sold to them, issue asset-backed securities to investors to fund the acquisition of the receivables and enter into derivatives or other yield maintenance contracts to hedge or mitigate certain risks related to the pool of receivables or assetbacked securities.
Additionally, the securitization vehicles are required to service the receivables they hold and the securities they have issued.
These servicing functions are performed by CarMax as appointed within the underlying legal documents.
Servicing functions include, but are not limited to, collecting payments from borrowers, monitoring delinquencies, liquidating assets, investing funds until distribution, remitting payments to the trustee who in turn remits payments to the investors, and accounting for and reporting information to investors.
ENDING MANAGED RECEIVABLES
## Table 2 ##
The special purpose entities and investors have no recourse to our assets.
Our risk under these arrangements is limited to the retained interest.
We have not provided financial or other support to the special purpose entities or investors that was not previously contractually required.
There are no additional arrangements, guarantees or other commitments that could require us to provide financial support or that would affect the fair value of our retained interest.
All transfers of receivables are accounted for as sales.
When the receivables are securitized, we recognize a gain or loss on the sale of the receivables as described in Note 3.
However, as described in Note 17, pursuant to ASUs 2009-16 and 2009-17, the transferred auto loan receivables, and the related non-recourse notes payable to the investors, will be accounted for as secured borrowings effective March 1, 2010, and will be reported on our consolidated balance sheets.
Retained Interest We retain an interest in the auto loan receivables that we securitize.
The retained interest includes the present value of the expected residual cash flows generated by the securitized receivables, or “interest-only strip receivables,”
The following table shows ONEOK Partners’ general partner and incentive distributions related to the periods indicated.
## Table 3 ##
The quarterly distributions paid by ONEOK Partners to limited partners in the first, second, third and fourth quarters of 2008 were $1.025 per unit, $1.04 per unit, $1.06 per unit, and $1.08 per unit, respectively.
In January 2009, ONEOK Partners declared a cash distribution of $1.08 per unit payable in the first quarter.
On February 13, 2009, we received the related incentive distribution of $20.3 million for the fourth quarter of 2008, which is included in the table above.
Relationship - We own 47.7 percent of ONEOK Partners and consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows from ONEOK Partners except for our distributions.
Distributions are declared quarterly by ONEOK Partners’ general partner based on the terms of its partnership agreement.
For the years ended December 31, 2008, 2007 and 2006, cash distributions declared from ONEOK Partners to us totaled $266.1 million, $207.4 million and $145.1 million, respectively.
See Note M for more information on ONEOK Partners results.
Affiliate Transactions - We have certain transactions with our ONEOK Partners affiliate and its subsidiaries, which comprise our ONEOK Partners segment.
ONEOK Partners sells natural gas from its natural gas gathering and processing operations to our Energy Services segment.
In addition, a large portion of ONEOK Partners’ revenues from its natural gas pipelines businesses are from our Energy Services and Distribution segments, which utilize ONEOK Partners’ natural gas transportation and storage services.
ONEOK Partners also purchases natural gas from our Energy Services segment for its natural gas liquids operations and its gathering and processing operations.
ONEOK Partners has certain contractual rights to the Bushton Plant through a Processing and Services Agreement with us, which sets out the terms for processing and related services we provide at the Bushton Plant through 2012.
ONEOK Partners has contracted for all of the capacity of the Bushton Plant from OBPI.
In exchange, ONEOK Partners pays us for all direct costs and expenses of the Bushton Plant, including reimbursement of a portion of our obligations under equipment leases covering the Bushton Plant.
We provide a variety of services to our affiliates, including cash management and financial services, employee benefits provided through our benefit plans, administrative services provided by our employees and management, insurance and office space leased in our headquarters building and other field locations.
Where costs are specifically incurred on behalf of an affiliate, the costs are billed directly to the affiliate by us.
In other situations, the costs may be allocated to the affiliates through a variety of methods, depending upon the nature of the expenses and the activities of the affiliates.
For example, a service that applies equally to all employees is allocated based upon the number of employees in each affiliate.
However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, earnings before interest and taxes and payroll expense.
Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments held for our continuing and discontinued operations for the periods indicated:
## Table 4 ##
These notional amounts are used to summarize the volume of financial instruments; however, they do not reflect the extent to which the positions offset one another and consequently do not reflect our actual exposure to market or credit risk.
Cash Flow Hedges - Our Energy Services and ONEOK Partners segments use derivative instruments to hedge the cash flows associated with anticipated purchases and sales of natural gas, NGLs and condensate and cost of fuel used in the transportation of natural gas.
Accumulated other comprehensive income (loss) at December 31, 2012, includes gains of approximately $0.9 million, net of tax, related to these hedges that will be recognized within the next 24 months as the forecasted transactions affect earnings.
If prices remain at current levels, we will recognize $0.4 million in net gains over the next 12 months, and we will recognize net gains of $0.5 million thereafter.
The remaining amounts deferred in accumulated other comprehensive income (loss) associated with derivative instruments are primarily attributable to our interest-rate swaps of which losses of $14.6 million will be reclassified into earnings during the next 12 months as the hedged items affect earnings.
For the year ended December 31, 2012, net margin in our Consolidated Statement of Income includes losses of $29.9 million related to certain financial contracts that were used to hedge forecasted purchases of natural gas.
As a result of the continued decline in natural gas prices, the combination of the cost basis of the forecasted purchases of inventory and the financial contracts exceed the amount expected to be recovered through sales of that inventory after considering related sales hedges, which requires reclassification of the loss from accumulated other comprehensive loss to current period earnings.
In 2011, cost of sales and fuel in our Consolidated Statements of Income included $91.1 million reflecting an adjustment to natural gas inventory at the lower of cost or market value.
We also reclassified $91.1 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings.
costs.
Our 2012 results were lower than 2011 when we realized $53.1 million in premium-services margins and our storage and marketing margins consisted of $96.0 million from realized seasonal price differentials and marketing optimization activities, and $87.7 million of storage demand costs.
In addition, we recognized a loss on the change in fair value of our nonqualifiying economic storage hedges of $1.0 million in 2012 compared with a gain of $8.5 million in 2011.
Our premium services were impacted negatively by lower natural gas prices and decreased natural gas price volatility.
The impact of our hedge strategies and the inability to hedge seasonal price differentials at levels that were available to us in the prior year significantly reduced our storage margins.
We also experienced reduced opportunities to optimize our storage assets, which negatively impacted our marketing margins.
We realized a loss in our transportation margins of $42.4 million in 2012 compared with a loss of $18.8 million in 2011, due primarily to a $29.5 million decrease in transportation hedges.
Our transportation business continues to be impacted by narrow price location differentials and the inability to hedge at levels that were available to us in prior years.
As a result of significant increases in the supply of natural gas, primarily from shale gas production across North America and new pipeline infrastructure projects, location and seasonal price differentials narrowed significantly beginning in 2010 and continuing through 2012.
This market change resulted in our transportation contracts being unprofitable impacting our ability to recover our fixed costs.
Operating costs decreased due primarily to lower employee-related expenses, which includes the impact of fewer employees.
We also recognized an expense of $10.3 million related to the impairment of our goodwill in the first quarter 2012.
Given the significant decline in natural gas prices and its effect on location and seasonal price differentials, we performed an interim impairment assessment in the first quarter 2012 that reduced our goodwill balance to zero.2011 vs.  2010 - The factors discussed in Energy Services’ “Narrative Description of the Business” included in Item I, Business, of this Annual Report have led to a significant decrease in net margin, including:?
a decrease of $65.3 million in transportation margins, net of hedging, due primarily to narrower location price differentials and lower hedge settlements in 2011;?
a decrease of $34.3 million in storage and marketing margins, net of hedging activities, due primarily to the following:– lower realized seasonal storage price differentials; offset partially by– favorable marketing activity and unrealized fair value changes on nonqualifying economic storage hedges;?
a decrease of $7.3 million in premium-services margins, associated primarily with the reduction in the value of the fees collected for these services as a result of low commodity prices and reduced natural gas price volatility in the first quarter 2011 compared with the first quarter 2010; and?
a decrease of $4.3 million in financial trading margins, as low natural gas prices and reduced natural gas price volatility limited our financial trading opportunities.
Additionally, our 2011 net margin includes $91.1 million in adjustments to natural gas inventory reflecting the lower of cost or market value.
Because of the adjustments to our inventory value, we reclassified $91.1 million of deferred gains on associated cash flow hedges into earnings.
Operating costs decreased due primarily to a decrease in ad valorem taxes.

<table><tr><td></td><td colspan="4">2011 Quarters</td><td colspan="4">2010 Quarters</td></tr><tr><td>(Dollars in millions, except per share information)</td><td>Fourth</td><td>Third</td><td>Second</td><td>First</td><td>Fourth</td><td>Third</td><td>Second</td><td>First</td></tr><tr><td>Reconciliation of net interest income to net interest income on a fully taxable-equivalent basis</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net interest income</td><td>$10,701</td><td>$10,490</td><td>$11,246</td><td>$12,179</td><td>$12,439</td><td>$12,435</td><td>$12,900</td><td>$13,749</td></tr><tr><td>Fully taxable-equivalent adjustment</td><td>258</td><td>249</td><td>247</td><td>218</td><td>270</td><td>282</td><td>297</td><td>321</td></tr><tr><td>Net interest income on a fully taxable-equivalent basis</td><td>$10,959</td><td>$10,739</td><td>$11,493</td><td>$12,397</td><td>$12,709</td><td>$12,717</td><td>$13,197</td><td>$14,070</td></tr><tr><td>Reconciliation of total revenue, net of interest expense to total revenue, net of interest expense on a fully taxable-equivalent basis</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total revenue, net of interest expense</td><td>$24,888</td><td>$28,453</td><td>$13,236</td><td>$26,877</td><td>$22,398</td><td>$26,700</td><td>$29,153</td><td>$31,969</td></tr><tr><td>Fully taxable-equivalent adjustment</td><td>258</td><td>249</td><td>247</td><td>218</td><td>270</td><td>282</td><td>297</td><td>321</td></tr><tr><td>Total revenue, net of interest expense on a fully taxable-equivalent basis</td><td>$25,146</td><td>$28,702</td><td>$13,483</td><td>$27,095</td><td>$22,668</td><td>$26,982</td><td>$29,450</td><td>$32,290</td></tr><tr><td>Reconciliation of total noninterest expense to total noninterest expense, excluding goodwill impairment charges</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total noninterest expense</td><td>$19,522</td><td>$17,613</td><td>$22,856</td><td>$20,283</td><td>$20,864</td><td>$27,216</td><td>$17,253</td><td>$17,775</td></tr><tr><td>Goodwill impairment charges</td><td>-581</td><td>—</td><td>-2,603</td><td>—</td><td>-2,000</td><td>-10,400</td><td>—</td><td>—</td></tr><tr><td>Total noninterest expense, excluding goodwill impairment charges</td><td>$18,941</td><td>$17,613</td><td>$20,253</td><td>$20,283</td><td>$18,864</td><td>$16,816</td><td>$17,253</td><td>$17,775</td></tr><tr><td>Reconciliation of income tax expense (benefit) to income tax expense (benefit) on a fully taxable-equivalent basis</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Income tax expense (benefit)</td><td>$441</td><td>$1,201</td><td>$-4,049</td><td>$731</td><td>$-2,351</td><td>$1,387</td><td>$672</td><td>$1,207</td></tr><tr><td>Fully taxable-equivalent adjustment</td><td>258</td><td>249</td><td>247</td><td>218</td><td>270</td><td>282</td><td>297</td><td>321</td></tr><tr><td>Income tax expense (benefit) on a fully taxable-equivalent basis</td><td>$699</td><td>$1,450</td><td>$-3,802</td><td>$949</td><td>$-2,081</td><td>$1,669</td><td>$969</td><td>$1,528</td></tr><tr><td>Reconciliation of net income (loss) to net income (loss), excluding goodwill impairment charges</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income (loss)</td><td>$1,991</td><td>$6,232</td><td>$-8,826</td><td>$2,049</td><td>$-1,244</td><td>$-7,299</td><td>$3,123</td><td>$3,182</td></tr><tr><td>Goodwill impairment charges</td><td>581</td><td>—</td><td>2,603</td><td>—</td><td>2,000</td><td>10,400</td><td>—</td><td>—</td></tr><tr><td>Net income (loss), excluding goodwill impairment charges</td><td>$2,572</td><td>$6,232</td><td>$-6,223</td><td>$2,049</td><td>$756</td><td>$3,101</td><td>$3,123</td><td>$3,182</td></tr><tr><td>Reconciliation of net income (loss) applicable to common shareholders to net income (loss) applicable to common shareholders, excluding goodwill impairment charges</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income (loss) applicable to common shareholders</td><td>$1,584</td><td>$5,889</td><td>$-9,127</td><td>$1,739</td><td>$-1,565</td><td>$-7,647</td><td>$2,783</td><td>$2,834</td></tr><tr><td>Goodwill impairment charges</td><td>581</td><td>—</td><td>2,603</td><td>—</td><td>2,000</td><td>10,400</td><td>—</td><td>—</td></tr><tr><td>Net income (loss) applicable to common shareholders, excluding goodwill impairment charges</td><td>$2,165</td><td>$5,889</td><td>$-6,524</td><td>$1,739</td><td>$435</td><td>$2,753</td><td>$2,783</td><td>$2,834</td></tr><tr><td>Reconciliation of average common shareholders’ equity to average tangible common shareholders’ equity</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Common shareholders’ equity</td><td>$209,324</td><td>$204,928</td><td>$218,505</td><td>$214,206</td><td>$218,728</td><td>$215,911</td><td>$215,468</td><td>$200,380</td></tr><tr><td>Common Equivalent Securities</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>11,760</td></tr><tr><td>Goodwill</td><td>-70,647</td><td>-71,070</td><td>-73,748</td><td>-73,922</td><td>-75,584</td><td>-82,484</td><td>-86,099</td><td>-86,334</td></tr><tr><td>Intangible assets (excluding MSRs)</td><td>-8,566</td><td>-9,005</td><td>-9,394</td><td>-9,769</td><td>-10,211</td><td>-10,629</td><td>-11,216</td><td>-11,906</td></tr><tr><td>Related deferred tax liabilities</td><td>2,775</td><td>2,852</td><td>2,932</td><td>3,035</td><td>3,121</td><td>3,214</td><td>3,395</td><td>3,497</td></tr><tr><td>Tangible common shareholders’ equity</td><td>$132,886</td><td>$127,705</td><td>$138,295</td><td>$133,550</td><td>$136,054</td><td>$126,012</td><td>$121,548</td><td>$117,397</td></tr></table>
<table><tr><td></td><td colspan="4"> 2008 Survival Ratios</td><td colspan="4"> 2007 Survival Ratios</td></tr><tr><td></td><td colspan="2"> 3 Year</td><td colspan="2"> 1 Year</td><td colspan="2"> 3 Year</td><td colspan="2"> 1 Year</td></tr><tr><td></td><td> Gross</td><td> Net</td><td> Gross</td><td> Net</td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td></tr><tr><td>Asbestos</td><td> 8.3</td><td> 9.6</td><td> 8.3</td><td> 18.2</td><td>10.2</td><td>10.7</td><td>10.6</td><td>10.6</td></tr><tr><td>Environmental</td><td> 3.5</td><td> 5.3</td><td> 2.7</td><td> 4.5</td><td>4.5</td><td>6.6</td><td>5.7</td><td>9.8</td></tr><tr><td>Total</td><td> 7.2</td><td> 8.2</td><td> 6.8</td><td> 11.2</td><td>8.9</td><td>9.3</td><td>9.6</td><td>10.4</td></tr></table>
<table><tr><td></td><td colspan="3">As of February 28 or 29</td></tr><tr><td>(In millions)</td><td>2010</td><td>2009</td><td>2008</td></tr><tr><td>Warehouse facility</td><td>$331.0</td><td>$1,215.0</td><td>$854.5</td></tr><tr><td>Term securitizations</td><td>3,615.6</td><td>2,616.9</td><td>2,910.0</td></tr><tr><td>Loans held for investment</td><td>135.5</td><td>145.1</td><td>69.0</td></tr><tr><td>Loans held for sale</td><td>30.6</td><td>9.7</td><td>5.0</td></tr><tr><td>Total ending managed receivables</td><td>$4,112.7</td><td>$3,986.7</td><td>$3,838.5</td></tr></table>
<table><tr><td></td><td colspan="3">Years Ended December 31,</td></tr><tr><td></td><td>2008</td><td>2007</td><td>2006</td></tr><tr><td></td><td colspan="3">(Thousands of dollars)</td></tr><tr><td>General partner distributions</td><td>$9,456</td><td>$7,842</td><td>$6,228</td></tr><tr><td>Incentive distributions</td><td>76,042</td><td>50,627</td><td>31,102</td></tr><tr><td>Total distributions to general partner</td><td>$85,498</td><td>$58,469</td><td>$37,330</td></tr></table>
<table><tr><td></td><td></td><td colspan="2">December 31, 2012</td><td colspan="2">December 31, 2011</td></tr><tr><td></td><td>ContractType</td><td>Purchased/Payor</td><td>Sold/Receiver</td><td>Purchased/Payor</td><td>Sold/Receiver</td></tr><tr><td colspan="2">Derivatives designated as hedging instruments:</td><td></td><td></td><td></td><td></td></tr><tr><td>Cash flow hedges</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fixed price</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>-Natural gas (Bcf)</td><td>Futures, forwards and swaps</td><td>—</td><td>-85.1</td><td>40.7</td><td>-135.3</td></tr><tr><td>-Crude oil and NGLs (MMBbl)</td><td>Futures, forwards and swaps</td><td>—</td><td>-1.1</td><td>—</td><td>-2.9</td></tr><tr><td>Basis</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>-Natural gas (Bcf)</td><td>Futures, forwards and swaps</td><td>—</td><td>-56.3</td><td>3.2</td><td>-82.8</td></tr><tr><td>Interest-rate contracts (Millions of dollars)</td><td>Forward-startingswaps</td><td>$400.0</td><td>—</td><td>$1,250.0</td><td>—</td></tr><tr><td>Fair value hedges</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basis</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>-Natural gas (Bcf)</td><td>Futures, forwards and swaps</td><td>59.1</td><td>-59.1</td><td>76.5</td><td>-77.0</td></tr><tr><td colspan="2">Derivatives not designated as hedging instruments:</td><td></td><td></td><td></td><td></td></tr><tr><td>Fixed price</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>-Natural gas (Bcf)</td><td>Futures, forwards and swaps</td><td>60.7</td><td>-60.4</td><td>312.7</td><td>-313.0</td></tr><tr><td></td><td>Options</td><td>102.1</td><td>-100.8</td><td>33.6</td><td>-14.3</td></tr><tr><td>Basis</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>-Natural gas (Bcf)</td><td>Futures, forwards and swaps</td><td>80.2</td><td>-81.7</td><td>216.9</td><td>-219.3</td></tr><tr><td>Index</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>-Natural gas (Bcf)</td><td>Futures, forwards and swaps</td><td>20.3</td><td>-22.3</td><td>29.3</td><td>-22.1</td></tr></table>

Question: What is the growing rate of -Natural gas (Bcf) in the years with the least Interest-rate contracts (Millions of dollars)?