September 27, 2005

VIA EDGAR AND FACSIMILE

Mr. George F. Ohsiek, Jr.

Branch Chief

Division of Corporation Finance

U.S. Securities and Exchange Commission

450 Fifth Street, N.W.

Mail Stop 3561

Washington, D.C. 20549

RE: MidAmerican Energy Holdings Company

Form 10-K for Fiscal Year Ended December 31, 2004

Filed March 1, 2005

Forms 10-Q for Fiscal Quarters Ended

March 31, 2005 and June 30, 2005

File No. 1-14881

MidAmerican Funding LLC

Form 10-K for Fiscal Year Ended December 31, 2004

Filed February 28, 2005

Forms 10-Q for Fiscal Quarters Ended

March 31, 2005 and June 30, 2005

File No. 333-90553

MidAmerican Energy Company

Form 10-K for Fiscal Year Ended December 31, 2004

Filed February 28, 2005

Forms 10-Q for Fiscal Quarters Ended

March 31, 2005 and June 30, 2005

File No. 333-15387

Dear Mr. Ohsiek:

This correspondence is being filed in response to comments received from the staff of the U.S. Securities and Exchange Commission (the “Commission”) by letter dated September 13, 2005 (the “Comments”) with respect to MidAmerican Energy Holdings Company (“MEHC” or the “Company”), MidAmerican Funding LLC (“Funding”) and MidAmerican Energy Company (“MidAmerican Energy”) and their respective Forms 10-K for the fiscal year ended December 31, 2004 (the “Form 10-K”) and their respective Forms 10-Q for the fiscal quarters ended March 31, 2005 and June 30, 2005 (the “Form 10-Q”). The numbering below corresponds to the numbering of the Comments, which have been incorporated into this response letter in italics.

MidAmerican Energy Holdings Company

Form 10-K for Fiscal Year Ended December 31, 2004

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 36

1.   On page 14, you disclose that the Philippine power plants will be transferred to the power purchaser at no cost at the end of the respective contract cooperation periods. We note that three out of four of the cooperation periods will end by 2007, resulting in potentially significant reductions in your operating revenues, earnings and fixed asset balances. As MD&A should focus specifically on material events known to management that would cause reported financial information not to be necessarily indicative of future operating results or of future financial condition, please revise your MD&A to describe how the end of these projects is expected to affect your future operating results and financial condition. See Item 303 of Regulation S-K.

Response: In preparing management’s discussion and analysis of financial condition and results of operations to be included in the Form 10-K for the year ended December 31, 2004, and the Forms 10-Q for the quarters ended March 31, 2005 and June 30, 2005, the Company considered including a discussion regarding the expected effects on future operating results and financial condition due to the expiration of the contract cooperation periods for the Upper Mahiao, Mahanagdong and Malitbog projects (collectively, the “Leyte Projects”). Such a discussion was not included in the respective filings as the expiration dates exceeded the reporting dates of each filing by more than one year and the expected effects were not determined to be quantitatively or qualitatively material.

The Company respectfully acknowledges the comment and will include in future quarterly and annual filings a discussion of the expected effects on future operating results and financial condition due to the expiration of the contract cooperation periods similar to the following:

“The ten-year cooperation periods for the Upper Mahiao, Mahanagdong and Malitbog projects (collectively, the “Leyte Projects”) end in June 2006, July 2007 and July 2007, respectively, at which time each project will be transferred to the Philippine National Oil Company-Energy Development Corporation (“PNOC-EDC”) at no cost on an “as-is” basis. For the year ended December 31, 2004, the Upper Mahiao Project’s financial results represented 0.7%, 1.4% and 2.1%, respectively, and the Mahanagdong and Malitbog Projects’ combined financial results represented 2.2%, 7.7% and 8.0%, respectively, of MEHC’s total consolidated operating revenue, income from continuing operations and operating cash flows from continuing operations. Additionally, both the net properties, plants and equipment and the project debt of the Leyte Projects represented 1.4% of MEHC’s total consolidated net properties, plants and equipment and subsidiary and project debt, respectively, at December 31, 2004.”

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Consolidated Balance Sheets, page 59

2. Based on review of your Form 10-Q for the period ended March 31, 2005, we note that you reclassified $123.6 million in auction rate securities from cash equivalents to short term investments in the accompanying December 31, 2004 balance sheet. As this reclassification appears to materially impact previously reported cash and cash equivalents, please amend your Form 10-K for the fiscal year ended December 31, 2004 to restate your balance sheets and statements of cash flows to reflect the reclassification. Please similarly amend your Form 10-K for MidAmerican Funding LLC and MidAmerican Energy Company to reflect such reclassification.

Response: The Company determined that this change in classification was not quantitatively or qualitatively material to its financial condition at December 31, 2004 and 2003, or its cash flows for the years ended December 31, 2004, 2003 and 2002. The net cash outflow from purchases and sales of auction rate securities at MEHC represents 5.0%, 2.3% and 1.8%, respectively, of investing cash flows from continuing operations for the years ended December 31, 2004, 2003 and 2002. These percentages are 6.2%, 0.0% and 0.0%, respectively, for the same periods at Funding and MidAmerican Energy. Further, the change in classification had no effect on the Company's (a) financial covenants; (b) regulatory matters; (c) previously reported amounts of total current assets, total assets or operating cash flows; and (d) discussion of liquidity and capital resources.

Accordingly, while the Company respectfully acknowledges the comment, the Company does not believe that amending the respective Forms 10-K is necessary for the quantitative and qualitative reasons discussed above.

Consolidated Statements of Cash Flows, page 62

3. Please either revise your statements of cash flows to separately present the cash inflows and outflows related to both affiliate notes and convertible preferred securities, or otherwise explain your basis under GAAP for netting these cash flows. See paragraphs 11-13 of SFAS 95.

Response: The amounts presented in the statements of cash flows for the years ended December 31, 2003 and 2002 in relation to investing cash flows for convertible preferred securities represent gross cash inflows and outflows as the Company purchased a convertible preferred security investment of The Williams Companies, Inc. in fiscal 2002 and sold that same investment in fiscal 2003. This is further described in Note 8 to the consolidated financial statements under the subheading “Williams Preferred Stock.”

For the year ended December 31, 2004, proceeds from affiliate notes totaled $14.1 million and there were no purchases of affiliate notes. For the year ended December 31, 2003, proceeds from affiliate notes totaled $2.6 million and purchases of affiliate notes totaled $(35.0) million. As the $2.6 million of proceeds received in fiscal 2003 was not quantitatively or qualitatively material to the Company’s overall cash flows statement presentation, it was netted with the purchases of affiliate notes.

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The Company respectfully acknowledges the comment and in future quarterly and annual filings will continue to separately present the gross cash inflows and outflows related to affiliate notes, when material to the overall cash flows statement presentation, in accordance with paragraphs 11-13 of SFAS 95.

Note 2. Summary of Significant Accounting Policies, page 63

4. Please revise to specifically address your revenue recognition policy for long-term power sales agreements in your CalEnergy Generation-Foreign segment. Tell us the pertinent terms of the agreements and related authoritative literature which supports your policy. Also tell us your consideration of the applicability of SFAS 13, EITF 01-8 and SFAS 133 to these arrangements, particularly as it relates to the take-or-pay terms of the agreements and the fact that you transfer the generation facilities to the purchaser at the end of the contracted cooperation period.

Response: Following is a summary of the pertinent terms of the agreements under which each of the Upper Mahiao, Mahanagdong and Malitbog projects (collectively, the “Leyte Projects”) and the Casecnan Project operates:

a.   The Leyte Projects - The Leyte Projects take geothermal steam and fluids, provided by the PNOC-EDC at no cost, and convert its thermal energy into electrical energy which is sold to the PNOC-EDC on a “take-or-pay” basis. PNOC-EDC pays the Company a fee based primarily on plant capacities. The ten-year cooperation periods end and the plants will be transferred to the PNOC-EDC at no cost on an “as-is” basis on June 18, 2006 for the Upper Mahiao Project and on July 25, 2007 for the Mahanagdong and Malitbog Projects.

The Upper Mahiao and Mahanagdong Projects’ primary source of revenue is from contractual plant capacity fees, which are flat over the cooperation periods, a portion of which is subject to semi-annual adjustment pursuant to changes in contractually specified price indices published periodically by the International Monetary Fund.

The Malitbog Project’s sole source of revenue is from contractual fees received for plant capacity. The majority of the fees are subject to a contractual declining fixed price schedule and the remaining fees are flat over the cooperation period subject to semi-annual adjustment similar to the Upper Mahiao and Mahanagdong Projects.

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b.   Casecnan Project - The Casecnan Project is a combined irrigation and hydroelectric power generation project that collects water and transfers that water through a 23 kilometer transbasin tunnel. During the water transfer, the elevation difference between the two watersheds allows electrical energy to be generated. A tailrace discharge tunnel then delivers water to an existing underutilized water storage reservoir. The electric energy and water are sold to the Philippine National Irrigation Administration (“NIA”). NIA pays the Company a fee for the delivery of water and a fee for the generation of electricity. The guaranteed water delivery fee is a fixed monthly payment based upon a contractually specified minimum annual water delivery amount multiplied by the applicable per cubic meter rate, which increases 7.5% annually for the first five years of operations and then remains fixed for the remainder of the cooperation period. For each contract year from 2004-2008, a water delivery credit is computed equal to 801.9 million cubic meters minus the greater of actual water deliveries or 700.0 million cubic meters multiplied by the applicable water delivery rate. The water delivery credit at the end of each contract year is available to be earned in the succeeding contract years ending in 2008. The cumulative water delivery credit at the end of 2008, if any, shall be amortized from 2009-2013. After 2008, water delivered in excess of the contractual minimum amount is subject to a variable water delivery fee equal to the water deliveries in excess of the annual contractual minimum multiplied by the applicable water delivery rate. With respect to electricity, the Company is paid a guaranteed energy delivery fee, which is flat over the cooperation period, for all deliveries of electricity up to 19,000 megawatt hours per month and a variable energy delivery fee for electricity delivered in excess of 19,000 megawatt hours per month, up to a contractually specified threshold.

Pursuant to the scope provisions of SFAS 13, the Company determined that the power sales agreements of the Leyte Projects and the Casecnan Project meet the definition of a lease. The distinction between other arrangements and leases having similar attributes depends on whether the agreement “conveys the right to use property, plant and equipment.” Since the Leyte Projects’ and the Casecnan Project’s power sales agreements transfer ownership of the properties at the end of the respective cooperation periods, the Company concluded that the agreements were leases within the scope of SFAS 13 and subject to its guidance.

This interpretation is consistent with the guidance provided in EITF 01-8, although that guidance had not been issued at the inception of the leases. Additionally, leases that are within the scope of SFAS 13 are not derivative instruments subject to SFAS 133.

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SFAS 13 utilizes several tests to determine if a lessor should account for a lease agreement as an operating or capital lease. If at the inception of the lease, as described in paragraph 8 of SFAS 13, the lease does not meet both of the following criteria, the lease should be classified as an operating lease: a) collectibility of the minimum lease payments is reasonably predictable, and b) no important uncertainties surround the amount of unreimbursable costs yet to be incurred by the lessor under the lease.

The leases were accounted for as operating leases as significant uncertainties existed at the inception of the leases regarding both the collection of future amounts and the amount of unreimbursable costs yet to be incurred. For example, the dependence on a single customer, the lack of operating history, the existence of significant operating uncertainties, and the existence of political, economic and other uncertainties associated with the Philippines were all listed as risk factors in the November 1995 confidential offering circular completed in connection with the initial construction financing for the Casecnan Project.

At the inception of the Leyte Projects’ and the Casecnan Project’s power sales agreements, agencies of the Philippine government, PNOC-EDC and NIA being only two, were contracting with numerous other international infrastructure developers for other major projects. A very real risk existed that the Philippine government was overextending itself in respect of paying for the goods and services once the projects commenced operations. Additionally, many of these contracts had payment obligations denominated in foreign currencies, which exposed the Philippine government to significant currency risk.¹

The uncertain political and economic environment in the Philippines at the inception of the Leyte Projects’ and the Casecnan Project’s power sales agreements provided further concerns in respect of the PNOC-EDC’s and NIA’s ability to meet its obligations. President Ramos was the first elected president in the Philippines since Ferdinand Marcos was driven from power in 1986. Muslim insurgents were actively fighting government forces in the southern islands and the economy was only beginning to recover from the effects of the Marcos regime. Half of the country’s population was employed in the low wage agricultural sector and poverty was widespread.

¹ The majority of receipts under the Leyte Projects’ and the Casecnan Project’s power sales agreements are denominated in U.S. dollars. Furthermore, a significant portion of the other infrastructure projects entered into are also denominated in currencies other than the Philippine Peso (“PHP”). Several events have contributed to a significant devaluation of the PHP. First, the Asian currency crisis, which began in June 1997 and went through June 1998, contributed to a 53% decline in the PHP relative to the U.S. dollar. Second, continuing political instability in the Philippines caused the PHP to decline by an additional 43% during 2000 and 2001 relative to the June 1997 exchange rate. These events add significant pressure to the Philippine government in respect of its foreign currency payment obligations.

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Since the commencement of commercial operations of the Leyte Projects and the Casecnan Project, the uncertainties existing at the beginning of the leases have manifested themselves in a number of ways. These include the PNOC-EDC’s refusal to pay amounts owed pursuant to the respective Leyte Projects’ power sales agreements, its rejection of all performance tests that formed the basis for the Leyte Projects’ annual capacity nominations, its subsequent refusal to pay for capacity resulting from such verified performance tests, its resistance in honoring awards granted to the Leyte Projects pursuant to binding international arbitral tribunals for damages suffered by the Leyte Projects due to PNOC-EDC conduct as well as its engagement in other practices to inhibit the Leyte Projects from operating the facilities as provided under the power sales agreements.

The Company’s conclusion based upon the circumstances was that the minimum lease payments were not reasonably predictable and that important uncertainties surrounding the amount of unreimbursable costs yet to be incurred did exist at the inception of the leases and the capital lease conditions were not met.

All variable energy and water delivery fees are recognized as earned similar to contingent rentals. All guaranteed fees are recognized on a straight-line basis pursuant to paragraph 19(b) of SFAS 13 over the cooperation periods with the exception of the guaranteed water delivery fee at the Casecnan Project, which increases 7.5% annually for the first five years of operations and then remains fixed for the remainder of the cooperation period. The Company believes that revenue is realizable only when circumstances are such that collection is reasonably assured pursuant to ARB 43, Chapter 1A paragraph 1. The uncertainty surrounding the Philippine business and economic environment (as previously discussed within this response), when considered along with the ultimate timing of collection and similar experiences within Indonesia raised sufficient doubt, in the judgment of management, regarding the realization of unbilled revenue. Accordingly, the Company made the decision to recognize revenue as billed for the guaranteed portion of the water delivery fee.

Additionally, the Company has determined that the disclosure requirements of paragraph 23(b) of SFAS 13 are not material to the overall financial statement presentation as 2004 minimum rentals and the net amount of properties, plant and equipment being leased at December 31, 2004 represented less than 5% of MEHC’s total consolidated operating revenue and net properties, plant and equipment, respectively. Further, variable energy fees for 2004, which would represent contingent rentals per SFAS 13, totaled only $28.7 million.

The Company respectfully acknowledges the comment and in future annual filings proposes to update the revenue recognition policy note for the long-term power sales agreements of the CalEnergy Generation-Foreign segment as follows:

“For the Leyte Projects and the Casecnan Project, the Company invoices PNOC-EDC and NIA on a monthly basis for the delivery of electricity and water pursuant to the provisions of their respective project agreements. The project agreements are accounted for as arrangements that contain both an operating lease and a service contract to operate the projects. The Leyte Projects’ primary source of revenue is from capacity fees recognized on a straight-line basis over the cooperation periods and subject to semi-annual adjustment pursuant to changes in contractually specified price indices.

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Additionally, for the Casecnan Project, the annual water delivery revenue is recorded on the basis of the contractual minimum guaranteed water delivery threshold for the respective contract year. If and when actual cumulative deliveries within a contract year exceed the minimum threshold, additional revenue is recognized and calculated as the product of the water deliveries in excess of the minimum threshold and the applicable unit price up to the maximum contractually allowed water delivery volume. The Company defers revenue on the difference between the actual water delivery fees earned and water delivery fees invoiced pursuant to the project agreement. Revenue from electricity consists of guaranteed energy fees, recognized on a straight-line basis over the cooperation period and a variable energy fee. The variable energy fee is recognized when deliveries of energy exceed the guaranteed energy in any contract year.”

Note 6. Properties, Plants and Equipment, Net, page 71

5.   Please disclose accumulated depreciation associated with your regulated and unregulated assets separately.

Response: The Company respectfully acknowledges the comment and will include in future quarterly and annual filings a disclosure similar to the following within the net properties, plants and equipment note to the consolidated financial statements:

“The utility generation and distribution system and interstate pipelines’ assets constitute the regulated assets of MidAmerican Energy, Kern River, Northern Natural Gas and CE Electric UK. At December 31, 2004, accumulated depreciation and amortization related to the Company’s regulated assets totaled approximately $4 billion.”

Note 18. Stock Transactions, page 83

6. Please revise to provide all of the disclosures required by paragraphs 45 through 48 of SFAS 123, as it appears that you have currently omitted a number of applicable disclosures. Otherwise, tell us why you believe the disclosures are not required.

Response: At December 31, 2001, there were 2,848,329 options outstanding and 2,555,276 options exercisable, all held by Mr. David L. Sokol, Chairman and Chief Executive Officer of MEHC, and Mr. Gregory E. Abel, President and Chief Operating Officer of MEHC. In 2002, the Company purchased 800,000 of the outstanding options held by Mr. Sokol. Additionally, 234,442 and 58,611 options vested in 2002 and 2003, respectively. There has been no other stock option activity since December 31, 2001. As the Company currently has no active stock option plans and the pro forma compensation cost, computed using the minimum value method pursuant to paragraphs 139-142 of SFAS 123, for fiscal 2002 and 2003 represents less than 1% of consolidated income from continuing operations for the years ended December 31, 2003 and 2002, the Company believes that the disclosures required by paragraphs 45 and 46 of SFAS 123 are not material to the Company’s overall financial statement presentation. However, the Company respectfully acknowledges the comment and will include a disclosure similar to the following in future annual filings to satisfy the disclosure requirements of paragraphs 47 and 48 of SFAS 123:

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“As of December 31, 2004 and 2003, there were 2,048,329 common stock options outstanding and exercisable with a weighted-average exercise price of $30.58 per share. There were no options granted, exercised, forfeited or allowed to expire during the years ended December 31, 2004, 2003 and 2002. In 2002, MEHC purchased 800,000 common stock options with a weighted-average exercise price of $26.10 held by Mr. David L. Sokol, its Chairman and Chief Executive Officer. MEHC paid Mr. Sokol an aggregate amount of $27.1 million, which was equal to the difference between the option exercise prices and an agreed upon per share value. 1,345,000 of the outstanding and exercisable options have exercise prices ranging from $15.94 to $34.69 per share, a weighted-average exercise price of $28.24 per share and a remaining contractual life of 3.25 years. The remaining 703,329 outstanding and exercisable options have an exercise price of $35.05 per share and a remaining contractual life of 5.25 years.”

Note 20. Regulatory Matters, page 85

7. You disclose that you have agreed not to seek a general increase in electric rates in Iowa prior to 2012 unless return on equity falls below 10%. Similarly, you disclose that Illinois bundled electric rates are frozen until 2007. As rates in Iowa and Illinois appear to be frozen for an extended period of time, please describe what consideration you gave, if any, to the continued applicability of SFAS 71 in such states. In doing so, please specifically address how you believe your current regulated rates are designed to recover your specific costs of providing service as discussed in paragraph 5.b of SFAS 71. Further, tell us if you will be able to recover certain costs, such as storm damage costs, incurred during the rate freeze upon or after completion of the freeze period.

Response: With respect to both Iowa and Illinois, MidAmerican Energy has earned and expects to continue to earn regulated returns sufficient to recover all costs of service since rates were “frozen”² (as noted in the comment) in each jurisdiction. The rates presently in effect are based on actual costs incurred by MidAmerican Energy in those jurisdictions in test years prior to 1997. The fact that base rates have not been changed since then is comparable to other periods of time in MidAmerican Energy’s history when rates remained stable. Even though the ability to adjust rates existed, it was unnecessary to do so, based on the costs incurred during those periods of time relative to the revenues recovered through the rates then in effect.

² The term “frozen” is used in a general sense. Technically, in Iowa rates for some customers may be raised or lowered in conjunction with rate adjustments for other customers that result in similar, offsetting revenue impacts. In Illinois and Iowa, customer rates are still impacted by changes in various rider mechanisms, including the fuel adjustment clause in Illinois.

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In Iowa the settlement agreements that result in the rate “freeze” specifically allow for rate relief in the event that equity returns fall below specified levels. While MidAmerican Energy does not anticipate the need for rate relief through 2011, it believes that it would be able to recover its costs of service in the event of a significant unfavorable financial event or events, based on the commitments of the parties to the settlement agreements.

Similarly, the Illinois law enacting deregulation in Illinois provides for the resumption of cost-based ratemaking after the “transition period” ends on December 31, 2006. During the transition period, utilities may take a number of actions, with limited regulatory interference, including the sale of their generation facilities or the spin-off of such facilities to a non-regulated affiliate. MidAmerican Energy has not taken any action permitted by the Illinois legislation that would jeopardize its ability to include generation costs in Illinois rates for 2007 and beyond.

Historically, very few (and presently no) customers in MidAmerican Energy’s Illinois service territory have procured their electric energy from alternative suppliers. To the extent that MidAmerican Energy’s Illinois customers do not choose an alternative energy supplier, MidAmerican Energy is required to continue serving such customers under bundled rates. Consistent with such an ongoing obligation to serve, MidAmerican Energy believes that its costs to serve such customers would be fully recoverable.

The Company respectfully acknowledges the comment and, for the reasons discussed above, believes that application of SFAS 71 to its electric operations in both Iowa and Illinois was appropriate in 2004 and continues to be appropriate.

Note 23. Segment Information, page 97

8. Please revise footnote (1) in the rollforward of your goodwill balance to explain in more detail the nature of the “other goodwill adjustments.” Ensure the explanation is clear in terms of why each type of adjustment is properly recorded through goodwill as opposed to through the statements of operations.

Response: The Company respectfully acknowledges the comment and will revise in future annual filings its goodwill rollforward as follows:

a.   Separately disclose the foreign currency translation adjustment, which relates only to the CE Electric UK reportable segment; and

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b.   Expand the goodwill significant accounting policy contained in Note 2 to the consolidated financial statements to include the following:

“The Company records goodwill adjustments for (a) changes in the estimates of or the settlement of tax bases of acquired assets, liabilities and carryforwards and items relating to acquired entities’ prior income tax returns, (b) the tax benefit associated with the excess of tax-deductible goodwill over the reported amount of goodwill and (c) changes to the purchase price allocation prior to the end of the allocation period, which is generally one year from the acquisition date.”

Item 9A. Controls and Procedures, page 101

9.   Please revise your disclosure regarding changes in internal control over financial reporting to identify any changes, rather than only significant changes, in your internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, your internal control over financial reporting. See Item 308(c) of Regulation S-K. Additionally, given this change, please confirm to us that there were no changes in internal control over financial reporting during the fourth fiscal quarter that materially affected, or are reasonably likely to materially affect, your internal control over financial reporting.

Response: The Company respectfully acknowledges the comment and will replace the last sentence of the disclosure included in Item 9A of the MEHC and Funding / MidAmerican Energy Forms 10-K for the year ended December 31, 2004, with the following, which is consistent with the disclosure included in Item 4 of the MEHC and Funding / MidAmerican Energy Forms 10-Q for the quarters ended March 31, 2005 and June 30, 2005, in future annual filings:

“There have been no changes during the fourth quarter in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.”

Additionally, the Company confirms to the Commission that there were no changes in internal control over financial reporting during the fourth fiscal quarter that materially affected, or were reasonably likely to materially affect, its internal control over financial reporting.

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MidAmerican Funding LLC

MidAmerican Energy Company

Form 10-K for Fiscal Year Ended December 31, 2004

10. Please revise to comply with the above comments, as applicable.

Response: The responses related to those comments applicable to the MidAmerican Funding LLC and MidAmerican Energy Company Form 10-K, which are numbers 2, 7 and 9, are presented within the respective responses above.

The Company acknowledges that: (1) the Company is responsible for the adequacy and accuracy of the disclosures in its filings, (2) staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing, and (3) the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under federal securities laws of the United States.

Please advise us if we can provide any further information to facilitate your review. Please direct any further questions or comments concerning this response letter to me at 515.281.2905.

Sincerely,

/s/ Patrick J. Goodman

Patrick J. Goodman

Senior Vice President and Chief Financial Officer

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