FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Mark One)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended October 31, 2007

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Layne Christensen Company

(Exact name of registrant as specified in its charter)

Delaware		48-0920712
State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1900 Shawnee Mission Parkway, Mission Woods, Kansas		66205
(Address of principal executive offices)		(Zip Code)

(Registrant’s telephone number, including area code) (913) 362-0510

Not Applicable
(Former name, former address and former fiscal year, if changed since last report.)

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

     Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o      Accelerated filer þ      Non-accelerated filer o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o      No þ

     There were 19,158,216 shares of common stock, $.01 par value per share, outstanding on November 30, 2007.

 

 

PART I

Item 1. Financial Statements

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)

		October 31,				January 31,
		2007				2007
		(unaudited)				(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	81,535			$	13,007
Customer receivables, less allowance of $7,308 and $7,020, respectively			125,776				109,615
Costs and estimated earnings in excess of billings on uncompleted contracts			59,027				51,210
Inventories			19,760				18,456
Deferred income taxes			17,748				16,551
Income taxes receivable			447				521
Restricted cash-current			—				8,270
Other			4,709				5,578
Total current assets			309,002				223,208
Property and equipment:
Land			8,649				8,180
Buildings			21,569				21,457
Machinery and equipment			291,449				263,049
Gas transportation facilities and equipment			27,897				24,939
Oil and gas properties			71,643				58,458
Mineral interests in oil and gas properties			17,424				12,515
			438,631				388,598
Less — Accumulated depreciation and depletion			(201,027	)			(174,081	)
Net property and equipment			237,604				214,517
Other assets:
Investment in affiliates			28,938				24,280
Goodwill			78,436				65,184
Other intangible assets, net			15,224				16,017
Other			5,589				3,958
Total other assets			128,187				109,439
		$	674,793			$	547,164

See Notes to Consolidated Financial Statements.

— Continued —

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS — (Continued)
(in thousands, except share and per share data)

		October 31,				January 31,
		2007				2007
		(unaudited)				(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	65,132			$	52,156
Current maturities of long-term debt			13,333				—
Accrued compensation			33,747				29,616
Accrued insurance expense			8,340				7,303
Cash purchase price adjustments			—				240
Other accrued expenses			16,086				14,222
Acquisition escrow obligation-current			50				9,395
Income taxes payable			3,492				9,045
Billings in excess of costs and estimated earnings on uncompleted contracts			31,441				34,242
Total current liabilities			171,621				156,219
Noncurrent and deferred liabilities:
Long-term debt			46,667				151,600
Accrued insurance expense			8,705				8,160
Deferred income taxes			26,063				23,302
Minority interest			371				—
Other			9,373				2,849
Total noncurrent and deferred liabilities			91,179				185,911
Common stock, par value $.01 per share, 30,000,000 shares authorized, 19,158,216 and 15,517,724 shares issued and outstanding, respectively			192				155
Capital in excess of par value			327,479				149,187
Retained earnings			92,260				64,145
Accumulated other comprehensive loss			(7,938	)			(8,453	)
Total stockholders’ equity			411,993				205,034
		$	674,793			$	547,164

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except share and per share data)

		Three Months								Nine Months
		Ended October 31,								Ended October 31,
		(unaudited)								(unaudited)
		2007				2006				2007				2006
Revenues		$	225,226			$	185,824			$	644,685			$	529,687
Cost of revenues (exclusive of depreciation, depletion and amortization shown below)			164,887				135,502				472,422				391,587
Selling, general and administrative expenses			31,457				26,724				89,977				75,324
Depreciation, depletion and amortization			11,228				8,673				31,927				23,139
Other income (expense):
Equity in earnings of affiliates			2,157				1,388				6,027				2,892
Interest			(2,517	)			(2,551	)			(7,744	)			(7,180	)
Other income, net			244				452				769				1,299
Income before income taxes and minority interest			17,538				14,214				49,411				36,648
Income tax expense			7,688				6,452				21,840				17,052
Minority interest			79				—				79				—
Net income		$	9,929			$	7,762			$	27,650			$	19,596
Basic income per share		$	0.60			$	0.51			$	1.74			$	1.28
Diluted income per share		$	0.59			$	0.50			$	1.70			$	1.27
Weighted average shares outstanding			16,477,000				15,334,000				15,857,000				15,282,000
Dilutive stock options			397,000				190,000				376,000				190,000
			16,874,000				15,524,000				16,233,000				15,472,000

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
(in thousands)

		Nine Months
		Ended October 31,
		(unaudited)
		2007				2006
Cash flow from operating activities:
Net income		$	27,650			$	19,596
Adjustments to reconcile net income to cash from operations:
Depreciation, depletion and amortization			31,927				23,139
Deferred income taxes			824				(2,064	)
Share-based compensation			2,139				1,661
Share-based compensation excess tax benefits			(2,204	)			—
Equity in earnings of affiliates			(6,027	)			(2,892	)
Dividends received from affiliates			1,369				1,038
Minority interest			(79	)			—
(Gain) loss from disposal of property and equipment			24				(789	)
Changes in current assets and liabilities, net of effects of acquisitions:
Increase in customer receivables			(15,102	)			(10,275	)
Increase in costs and estimated earnings in excess of billings on uncompleted contracts			(7,770	)			(8,721	)
Increase in inventories			(918	)			(1,067	)
Decrease in other current assets			1,116				1,243
Increase in accounts payable and accrued expenses			21,678				25,412
Increase (decrease) in billings in excess of costs and estimated earnings on uncompleted contracts			(2,801	)			10,012
Other, net			(1,374	)			(729	)
Cash provided by operating activities			50,452				55,564
Cash flow from investing activities:
Additions to property and equipment			(33,152	)			(23,899	)
Additions to gas transportation facilities and equipment			(2,958	)			(11,268	)
Additions to oil and gas properties			(13,171	)			(19,441	)
Additions to mineral interests in oil and gas properties			(4,908	)			(1,339	)
Proceeds from disposal of property and equipment			1,339				3,372
Acquisition of businesses, net of cash acquired			—				(3,809	)
Acquisition of oil and gas transportation facilities and equipment			—				(1,500	)
Distribution of restricted cash for prior year acquisitions			(9,627	)			—
Payment of cash purchase price adjustments on prior year acquisition			(2,270	)			(6,120	)
Deposit of cash into restricted accounts			(1,075	)			(1,887	)
Release of cash from restricted accounts			9,627				5,597
Net investment in affiliates			—				400
Cash used in investing activities			(56,195	)			(59,894	)
Cash flow from financing activities:
Borrowings under revolving credit facility			483,800				267,400
Repayments under revolving credit facility			(575,400	)			(265,300	)
Proceeds from public offering of common stock, net of issuance costs			159,879				—
Issuance of common stock upon exercise of stock options			2,845				1,161
Excess tax benefit on exercise of share-based instruments			2,204				571
Contribution from minority interest			450				—
Cash provided by financing activities			73,778				3,832
Effects of exchange rate changes on cash			493				225
Net increase (decrease) in cash and cash equivalents			68,528				(273	)
Cash and cash equivalents at beginning of period			13,007				17,983
Cash and cash equivalents at end of period		$	81,535			$	17,710

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Accounting Policies and Basis of Presentation

Principles of Consolidation — The consolidated financial statements include the accounts of Layne Christensen Company and its subsidiaries (together, the “Company”). All significant inter-company transactions have been eliminated. Investments in affiliates (20% to 50% owned) in which the Company exercises influence over operating and financial policies are accounted for by the equity method. The unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements of the Company for the year ended January 31, 2007 as filed in its Annual Report on Form 10-K.

The accompanying unaudited consolidated financial statements include all adjustments (consisting only of normal recurring accruals) which, in the opinion of management, are necessary for a fair presentation of financial position, results of operations and cash flows. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

Use of Estimates in Preparing Financial Statements — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue Recognition — Revenues are recognized on large, long-term construction contracts meeting the criteria of Statement of Position 81-1, Accounting for Performance of Construction-Type and Certain Production-Type Contracts (“SOP 81-1”), using the percentage-of-completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. As allowed by SOP 81-1, revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.

Revenues for direct sales of equipment and other ancillary products not provided in conjunction with the performance of construction contracts are recognized at the date of delivery to, and acceptance by, the customer. Provisions for estimated warranty obligations are made in the period in which the sales occur.

Contracts for the Company’s mineral exploration drilling services are billable based on the quantity of drilling performed. Thus, revenues for these drilling contracts are recognized on the basis of actual footage or meterage drilled.

Revenues for the sale of oil and gas by the Company’s energy division are recognized on the basis of volumes sold at the time of delivery to an end user or an interstate pipeline, net of amounts attributable to royalty or working interest holders.

The Company’s revenues are presented net of taxes imposed on revenue-producing transactions with its customers, such as, but not limited to, sales, use, value-added, and some excise taxes.

Oil and gas properties and mineral interests — The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, and salaries, benefits and other internal salary-related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.

The Company is required to review the carrying value of its oil and gas properties each quarter under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and gas properties, as adjusted for asset retirement obligations, may not exceed the present value of estimated future net revenues from proved reserves, discounted

at 10% (the “Ceiling Test”). Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the last day of the quarter, with effect given to the Company’s fixed-price natural gas contracts, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows. The Company believes at this time that the carrying value of its oil and gas properties is appropriate.

Reserve Estimates — The Company’s estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas reserves and future net cash flows depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and work over and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.

Goodwill and Other Intangibles — Goodwill and other intangible assets with indefinite useful lives are not amortized, and instead are periodically tested for impairment. The Company performs its annual impairment test as of December 31 each year, or more frequently if events or changes in circumstances indicate that an asset might be impaired. The process of evaluating goodwill for impairment involves the determination of the fair value of the Company’s reporting units. Inherent in such fair value determinations are certain judgments and estimates, including the interpretation of current economic indicators and market valuations, and assumptions about the Company’s strategic plans with regard to its operations. The Company believes at this time that the carrying value of the remaining goodwill is appropriate, although to the extent additional information arises or the Company’s strategies change, it is possible that the Company’s conclusions regarding impairment of the remaining goodwill could change and result in a material effect on its financial position or results of operations.

Other Long-lived Assets — In the event of an indication of possible impairment, the Company evaluates the fair value and future benefits of long-lived assets, including the Company’s gas transportation facilities and equipment, by performing an analysis of the anticipated future net cash flows of the related long-lived assets. In the event of an impairment, the carrying value of those assets would be reduced to fair value. The Company believes at this time that the carrying values and useful lives of its long-lived assets continue to be appropriate.

Cash and Cash Equivalents — The Company considers investments with an original maturity of three months or less when purchased to be cash equivalents. As of October 31, 2007, the Company’s cash equivalents included $59,000,000 of short term commercial paper. The Company’s cash equivalents are subject to potential credit risk. The company’s cash management and investment policies restrict investments to investment grade, highly liquid securities. The carrying value of cash and cash equivalents approximates fair value.

Accrued Insurance Expense — The Company maintains insurance programs where it is responsible for a certain amount of each claim up to a self-insured limit. Estimates are recorded for health and welfare, property and casualty insurance costs that are associated with these programs. These costs are estimated based on actuarially determined projections of future payments under these programs. Should a greater amount of claims occur compared to what was estimated or costs of the medical profession increase beyond what was anticipated, reserves recorded may not be sufficient and additional costs to the consolidated financial statements could be required.

Costs estimated to be incurred in the future for employee medical benefits, property, workers’ compensation and casualty insurance programs resulting from claims which have occurred are accrued currently. Under the terms of the Company’s agreement with the various insurance carriers administering these claims, the Company is not required to remit the total premium until the claims are actually paid by the insurance companies. These costs are not expected to significantly impact liquidity in future periods.

Income Taxes — Income taxes are provided using the asset/liability method, in which deferred taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax assets are reviewed for recoverability and valuation allowances are provided as necessary. Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on those amounts in excess of funds considered to be invested indefinitely.

The Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement 109” (“FIN 48”), effective February 1, 2007. FIN 48 prescribes a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition of income tax assets or liabilities, classification of current and deferred income tax assets and liabilities, accounting for interest and penalties associated with tax positions, accounting for income taxes in interim periods and income tax disclosures. The cumulative effects of applying FIN 48 have been recorded as an increase to retained earnings and a decrease to income taxes payable of $465,000 as of February 1, 2007. As of October 31, and February 1, 2007, the total amount of unrecognized tax benefits was $7,154,000 and $6,061,000, respectively of which substantially all would affect the effective tax rate if recognized. The Company does not expect the unrecognized tax benefits to change materially within the next 12 months.

In conjunction with the adoption of FIN 48, the Company has classified uncertain tax positions as non-current income tax liabilities unless expected to be paid in one year. Consistent with its historical financial reporting, the Company reports income tax-related interest and penalties as a component of income tax expense. As of October 31 and February 1, 2007, the total amount of accrued income tax-related interest and penalties included in the balance sheet was $2,021,000 and $1,489,000, respectively.

The Company has been examined for federal income tax purposes for the 1999-2003 tax years. During the first quarter of fiscal 2008, the Company effectively settled certain tax years which resulted in the recognition of $706,000 in previously unrecognized tax benefits. The 2004-2007 tax years are open to possible federal and state examination. The Company is also open to examination in various foreign jurisdictions for various tax years ranging from 2002-2007 subject to the normal statute of limitation rules in each country. Tax liabilities are recorded based on estimates of additional taxes which will be due upon the conclusion of these examinations. Estimates of these tax liabilities are made based upon prior experience and are updated in light of changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, examination outcomes and the timing of settlements are subject to significant uncertainty.

Litigation and Other Contingencies — The Company is involved in litigation incidental to its business, the disposition of which is not expected to have a material effect on the Company’s business, financial position, results of operations or cash flows. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. The Company accrues its best estimate of the probable cost for the resolution of legal claims. Such estimates are developed in consultation with outside counsel handling these matters and are based upon a combination of litigation and settlement strategies. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.

Derivatives — The Company follows SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, which requires derivative financial instruments to be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships. Under SFAS 133, the Company accounts for its unrealized hedges of forecasted costs as cash flow hedges, such that changes in fair value for the effective portion of hedge contracts, if material, are recorded in accumulated other comprehensive income in stockholders’ equity. Changes in the fair value of the effective portion of hedge contracts are recognized in accumulated other comprehensive income until the hedged item is recognized in operations. The ineffective portion of the derivatives change in fair value, if any, is immediately recognized in operations. In addition, the Company has entered into fixed-price natural gas contracts to manage fluctuations in the price of natural gas. These contracts result in the Company physically delivering gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts (see Note 5 for disclosure regarding the fair value of derivative instruments). The Company does not enter into derivative financial instruments for speculative or trading purposes.

Earnings per share — Earnings per share are based upon the weighted average number of common and dilutive equivalent shares outstanding. Options to purchase common stock are included based on the treasury stock method for dilutive earnings per share, except when their effect is antidilutive.

Share-based compensation — The Company adopted SFAS No. 123R (revised December 2004), “Shared-Based Compensation” effective February 1, 2006, which requires the recognition of all share-based instruments in the financial statements and establishes a fair-value measurement of the associated costs. The Company elected to adopt the standard using the Modified Prospective Method which requires recognition of all unvested share-based instruments as of the effective date over the remaining term of the instrument. As of October 31, 2007, the Company had unrecognized compensation expense of $5,479,000 to be recognized over a weighted average period of 2.53 years. The Company determines the fair value of stock-based compensation using the Black-Scholes model. As of October 31, 2007, there was approximately $2,782,000 of unearned compensation cost related to unvested restricted shares. This amount is expected to be recognized over a weighted average period of 3.47 years.

Consolidated Statements of Cash Flows – Highly liquid investments with an original maturity of three months or less at the time of purchase are considered cash equivalents.

Supplemental Cash Flow Information – The amounts paid for income taxes, net of refunds, and interest is as follows (in thousands):

		Nine Months
		Ended October 31,
		2007				2006
Income taxes		$	15,761			$	10,871
Interest			7,717				7,012

The Company had earnings on restricted cash of $282,000 and $144,000 for the nine months ended October 31, 2007 and 2006, which were treated as non-cash items as they were restricted for the account of the escrow beneficiaries.

2. Acquisitions

On September 28, 2005, the Company acquired 100% of the outstanding stock of Reynolds Inc. (“Reynolds”). Under the terms of the purchase, there was contingent consideration up to a maximum of $15,000,000 (the “Reynolds Earn out”), based on Reynolds operating performance over a period of thirty-six months from the closing date. During July 2007, the Company determined that it was probable that the maximum consideration would be achieved, and agreed to settle the Reynolds Earn out on a discounted basis for $13,252,000, consisting of $2,270,000 in cash and $10,982,000 of Layne common stock. The Company paid the cash portion of the settlement on July 31, 2007, and issued 249,023 shares of Layne common stock in August 2007 in payment of the stock portion. The Reynolds Earnout has been accounted for as additional purchase consideration, and accordingly the Company recorded $13,252,000 of additional Goodwill in July, 2007.

On November 20, 2006, the Company acquired 100% of the stock of American Water Services Underground Infrastructure, Inc. (“UIG”), a wholly-owned subsidiary of American Water (USA), Inc. UIG is engaged in the business of providing trenchless pipeline rehabilitation services for sewer and storm water systems and was combined with a similar service line acquired in the acquisition of Reynolds, Inc. The purchase price for UIG was $27,662,000, consisting of cash of $27,524,000 and costs of $138,000. The cash portion of the purchase price was net of certain purchase price adjustments based on the amount of tangible net worth at the closing date, $1,101,000 of which was received by the Company in February 2007.

The purchase price has been allocated based on the fair value of the assets and liabilities acquired, determined based on UIG’s historical cost basis of assets and liabilities, appraisals and other analyses. Based on the Company’s allocation of the purchase price, the acquisition had the following effect on the Company’s consolidated financial position (in thousands):

Working capital		$	11,723
Property and equipment			13,602
Goodwill			3,891
Trade names			143
Other intangible assets			69
Deferred income taxes			(1,766	)
Total purchase price		$	27,662

The results of operations of UIG have been included in the Company’s consolidated statements of income commencing with the closing date. Assuming UIG had been acquired as of the beginning of fiscal 2007, the unaudited consolidated revenues, net income from continuing operations, net income and net income per share would have been as follows (in thousands, except per share data):

		Three Months Ended								Nine Months Ended
		October 31,								October 31,
		2007				2006				2007				2006
Revenues		$	225,226			$	197,853			$	644,685			$	564,892
Net income			9,929				8,348				27,650				20,563
Basic earnings per share			0.60				0.54				1.74				1.35
Diluted earnings per share			0.59				0.54				1.70				1.33

The pro forma information provided above is not necessarily indicative of the results of operations that would actually have resulted if the acquisition was made as of those dates or of results that may occur in the future. Pro forma results include adjustments for interest expense on the cash purchase price and depreciation and amortization expense on the acquisition adjustments to property and equipment and other intangible assets.

In July 2006 and January 2007, the Company purchased certain gas wells and mineral interests in oil and gas properties from unrelated operators totaling $1,988,000 in cash. The acquisitions complemented the Company’s existing operation in the mid-continent region of the United States. The purchase price was allocated $1,376,000 to oil and gas properties and $612,000 to mineral interests in oil and gas properties.

On June 16, 2006 (the “CWI Closing Date”), the Company acquired 100% of the stock of Collector Wells International, Inc. (“CWI”), a privately held specialty water services company that designs and constructs water supply systems. CWI was combined with a similar service line acquired in the acquisition of Reynolds, Inc. The purchase price for CWI was $5,442,000, consisting of $3,150,000 cash, 45,563 shares of Layne common stock (valued at $1,263,000), cash purchase price adjustments and costs of $1,029,000. Layne common stock was valued in the transaction based upon a five-day average of the closing price of the stock two days before and two days after the CWI Closing Date. The stock was placed in escrow to secure certain representations, warranties and indemnifications under the purchase agreement and will be released in three annual installments. The cash purchase price adjustments were based on the amount by which working capital at the CWI Closing Date exceeded a threshold amount established in the purchase agreement.

In addition, there is contingent consideration up to a maximum of $1,400,000 (the “CWI Earnout Amount”), which is based on a percentage of the amount by which CWI’s earnings before interest, taxes, depreciation and amortization exceed a threshold amount during the thirty-six months following the acquisition. If earned, up to 20% of the CWI Earnout Amount may be paid with Layne common stock, at the Company’s discretion. Any portion of the CWI Earnout Amount which is ultimately paid will be accounted for as additional purchase consideration.

The purchase price has been allocated based on the fair value of the assets and liabilities acquired, determined based on CWI’s historical cost basis of assets and liabilities and other analyses. Based on the Company’s allocation of the purchase price, the acquisition had the following effect on the Company’s consolidated financial position (in thousands):

Working capital		$	1,016
Property and equipment			1,580
Goodwill			3,436
Deferred income taxes			(590	)
Total Purchase Price		$	5,442

The results of operations of CWI have been included in the Company’s consolidated statements of income commencing with the CWI Closing Date. On a pro forma basis for periods prior to the acquisition, the acquisition did not have a significant effect on the Company’s results of operations or cash flows.

On November 30, 2007, the Company acquired certain assets of SolmeteX, Inc., a wastewater treatment company, for approximately $13,500,000.

3. Goodwill and Other Intangible Assets

Goodwill and other intangible assets consist of the following (in thousands):

		October 31, 2007												January 31, 2007
										Weighted												Weighted
										Average												Average
		Gross								Amortization				Gross								Amortization
		Carrying				Accumulated				Period in				Carrying				Accumulated				Period in
		Amount				Amortization				years				Amount				Amortization				years
Goodwill (non tax deductible)		$	78,436			$	—							$	65,184			$	—
Other amortizable intangible assets
Tradenames		$	16,000			$	(1,278	)			32			$	16,000			$	(818	)			32
Customer-related			332				(263	)			3				332				(134	)			3
Patents			359				(276	)			3				359				(160	)			3
Non-competition agreements			379				(261	)			5				379				(227	)			5
Other			762				(530	)			23				762				(476	)			23
Total amortizable intangible assets		$	17,832			$	(2,608	)						$	17,832			$	(1,815	)

Amortizable intangible assets are being amortized over their estimated useful lives of one to 40 years with a weighted average amortization period of 30 years. Total amortization expense for other intangible assets was $265,000 and $244,000 for three months ended October 31, 2007 and 2006, respectively, and $793,000 and $730,000 for the nine months ended October 31, 2007 and 2006, respectively.

The carrying amount of goodwill attributed to each operating segment was as follows (in thousands):

						Water and Wastewater
		Energy				Infrastructure				Total
Balance February 1, 2007		$	950			$	64,234			$	65,184
Additions			—				13,252				13,252
Balance, October 31, 2007		$	950			$	77,486			$	78,436

4. Indebtedness

On July 31, 2003, the Company entered into an agreement (“Master Shelf Agreement”) whereby it could issue up to $60,000,000 in unsecured notes. Upon closing, the Company issued $40,000,000 of notes (“Series A Senior Notes”) under the Master Shelf Agreement. The Series A Senior Notes bear a fixed interest rate of 6.05% and are due on July 31, 2010, with annual principal payments of $13,333,000 beginning July 31, 2008. Proceeds from the issuance were used to refinance borrowings outstanding under the Company’s previous term loan and revolving credit facility. The Company issued an additional $20,000,000 of notes under the Master Shelf Agreement in October 2004 (“Series B Senior Notes”). The Series B Senior Notes bear a fixed interest rate of 5.40% and are due on September 29, 2011, with annual principal payments of $6,667,000 beginning September 29, 2009. Proceeds of the issuance were used to finance an acquisition and for general corporate purposes. As of October 15, 2007, the Company amended the Master Shelf Agreement to increase the amount of senior notes available to be issued to $105,000,000, which created an available facility amount of $45,000,000, and reinstated and extended the available issuance period to September 15, 2009.

Also, concurrent with the acquisition of Reynolds, the Company expanded its existing revolving credit facility with LaSalle Bank National Association, as Administrative Agent, and a group of additional banks by entering into an Amended and Restated Loan Agreement (the “Credit Agreement”) with LaSalle Bank National Association, as Administrative Agent and as Lender (the “Administrative Agent”), and the other Lenders listed therein (the “Lenders”), which increased the Company’s revolving loan commitment from $70,000,000 to $130,000,000, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit). Approximately $80,000,000 of the facility was used to pay the cash portion of the acquisition of Reynolds and refinance the outstanding borrowings under the previous credit agreement. The Credit Agreement was also amended in November 2006, concurrent with the acquisition of UIG, and the revolving loan commitment was increased to $200,000,000.

The Credit Agreement provides for interest at variable rates equal to, at the Company’s option, a LIBOR rate plus 0.75% to 2.00%, or a base rate, as defined in the Credit Agreement plus up to 0.50%, depending upon the Company’s leverage ratio. The Credit Agreement is unsecured and is due and payable November 15, 2011. On October 31, 2007, there were letters of credit of $13,717,000 and no borrowings outstanding on the Credit Agreement resulting in available capacity of $186,283,000.

The Master Shelf Agreement and the Credit Agreement contain certain covenants including restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions, transfer or sale of assets, transactions with affiliates, payment of dividends and certain financial maintenance covenants, including among others, fixed charge coverage, maximum debt to EBITDA and minimum tangible net worth. The Company was in compliance with its covenants as of October 31, 2007.

Debt outstanding as of October 31, 2007 and January 31, 2007 was as follows (in thousands):

		October 31,				January 31,
		2007				2007
Credit Agreement		$	—			$	91,600
Senior Notes			60,000				60,000
Total debt			60,000				151,600
Less current maturities			13,333				—
Total long-term debt		$	46,667			$	151,600

5. Derivatives

The Company’s energy division is exposed to fluctuations in the price of natural gas and has entered into fixed-price physical delivery contracts to manage natural gas price risk for a portion of its production. As of October 31, 2007, the Company had committed to deliver 5,018,000 million British Thermal Units (“MMBtu”) of natural gas through March 2010. The prices on these contracts range from $7.46 to $9.015 per MMBtu.

The fixed-price physical delivery contracts will result in the physical delivery of natural gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts. The estimated fair value of such contracts at October 31, 2007 was $2,821,000.

Additionally, the Company has foreign operations that have significant costs denominated in foreign currencies, and thus is exposed to risks associated with changes in foreign currency exchange rates. At any point in time, the Company might use various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with forecasted expatriate labor costs and purchases of operating supplies. The Company does not enter into foreign currency derivative financial instruments for speculative or trading purposes.

6. Other Comprehensive Income (Loss)

Components of other comprehensive income (loss) are summarized as follows (in thousands):

		Three Months Ended								Nine Months Ended
		October 31,								October 31,
		2007				2006				2007				2006
Net income		$	9,929			$	7,762			$	27,650			$	19,596
Other comprehensive income, net of taxes:
Foreign currency translation adjustments			23				(60	)			515				142
Unrealized gain on foreign exchange contracts			—				(56	)			—				53
Other comprehensive income		$	9,952			$	7,646			$	28,165			$	19,791

The components of accumulated other comprehensive loss as of October 31, 2007 and 2006 are as follows (in thousands):

										Unrealized				Accumulated
		Cumulative				Unrecognized				Gain				Other
		Translation				Pension				on Exchange				Comprehensive
		Adjustment				Liability				Contracts				Loss
Balance, February 1, 2007		$	(7,151	)		$	(1,302	)		$	—			$	(8,453	)
Period change			515				—				—				515
Balance, October 31, 2007		$	(6,636	)		$	(1,302	)		$	—			$	(7,938	)

										Unrealized				Accumulated
		Cumulative				Unrecognized				Gain				Other
		Translation				Pension				on Exchange				Comprehensive
		Adjustment				Liability				Contracts				Loss
Balance, February 1, 2006		$	(7,442	)		$	—			$	—			$	(7,442	)
Period change			142				—				53				195
Balance, October 31, 2006		$	(7,300	)		$	—			$	53			$	(7,247	)

7. Employee Benefit Plans

The Company sponsors a pension plan covering certain hourly employees not covered by union-sponsored, multi-employer plans. Benefits are computed based mainly on years of service. The Company makes annual contributions to the plan substantially equal to the amounts required to maintain the qualified status of the plans. Contributions are intended to provide for benefits related to past and current service with the Company. Effective December 31, 2003, the Company froze the pension plan. Benefits will no longer be accrued after December 31, 2003, and no further employees will be added to the Plan. The Company expects to maintain the assets of the Plan to pay normal benefits accrued through December 31, 2003. Assets of the plan consist primarily of stocks, bonds and government securities.

Net periodic pension cost for the three and nine months ended October 31, 2007 and 2006 includes the following components (in thousands):

		Three Months Ended								Nine Months Ended
		October 31,								October 31,
		2007				2006				2007				2006
Service cost		$	23			$	22			$	72			$	64
Interest cost			117				110				353				329
Expected return on assets			(133	)			(130	)			(402	)			(387	)
Net amortization			60				62				180				185
Net periodic pension cost		$	67			$	64			$	203			$	191

The Company also provides supplemental retirement benefits to its chief executive officer. Benefits are computed based on the compensation earned during the highest five consecutive years of employment reduced for a portion of Social Security benefits and an annuity equivalent of the chief executive’s defined contribution plan balance. The Company does not contribute to the plan or maintain any investment assets related to the expected benefit obligation. The Company has recognized the full amount of its actuarially determined pension liability. Net periodic pension cost of the supplemental retirement benefits for the three and nine months ended October 31, 2007 and 2006 include the following components (in thousands):

		Three Months Ended								Nine Months Ended
		October 31,								October 31,
		2007				2006				2007				2006
Service cost		$	44			$	25			$	132			$	75
Interest cost			26				22				77				66
Net periodic pension cost		$	70			$	47			$	209			$	141

8. Stock and Stock Option Plans

In October 2007, the Company completed a public stock offering of 3,105,000 common shares. Proceeds of the offering, net of issuance costs of $9,344,000, were $159,879,000.

In October 1998, the Company adopted a Rights Agreement whereby the Company has authorized and declared a dividend of one preferred share purchase right (“Right”) for each outstanding common share of the Company. Subject to limited exceptions, the Rights are exercisable if a person or group acquires or announces a tender offer for 25% or more of the Company’s common stock. Each Right will entitle shareholders to buy one one-hundredth of a share of a newly created Series A Junior Participating Preferred Stock of the Company at an exercise price of $45.00. The Company is entitled to redeem the Right at $0.01 per Right at any time before a person has acquired 25% or more of the Company’s outstanding common stock. The Rights expire 10 years from the date of grant.

The Company has stock option and employee incentive plans that provide for the granting of options to purchase or the issuance of shares of common stock up to an aggregate of 2,600,000 shares of common stock at a price fixed by the Board of Directors or a committee. As of October 31, 2007, there were 336,000 shares available to be granted under the plans. The Company has the ability to issue shares under the plans either from new issuances or from treasury, although it has previously always issued new shares and expects to continue to issue new shares in the future.

For the nine months ended October 31, 2007, the Company granted approximately 74,000 restricted shares which generally cliff vest over periods of 1-4 years from the grant date.

Significant option groups outstanding at October 31, 2007, related exercise price and remaining contractual term follows:

														Remaining
														Contractual
Grant		Options				Options				Exercise				Term
Date		Outstanding				Exercisable				Price				(Months)
4/98			736				736				10.290				6
4/99			9,773				9,773				4.125				18
4/99			24,875				24,875				5.250				18
2/00			3,500				3,500				5.500				28
4/00			14,794				14,794				3.495				30
6/04			25,000				25,000				16.600				80
6/04			169,791				101,041				16.650				81
6/05			12,000				12,000				17.540				93
9/05			203,750				78,750				23.050				96
1/06			200,231				42,558				27.870				100
6/06			12,000				12,000				29.290				105
6/06			70,000				17,500				29.290				105
6/07			70,000				—				42.260				115
7/07			33,000				—				42.760				116
9/07			3,000				—				55.480				119
			852,450				342,527

All options were granted at an exercise price equal to the fair market value of the Company’s common stock at the date of grant. The options have terms of 5 to 10 years from the date of grant and generally vest ratably over periods of 4 to 5 years. Transactions for stock options for the period ended October 31, 2007 were as follows:

										Weighted
										Average
						Weighted				Remaining				Intrinsic
		Number of				Average				Contractual Term				Value
		Shares				Exercise Price				(years)				(in thousands)
Stock Option Activity Summary:
Outstanding at February 1, 2007			963,529			$	20.028				7.410			$	14,454
Granted			106,000				42.79								—
Exercised			(212,606	)			13.390								6,812
Canceled			—				—								—
Forfeited			(3,750	)			16.65								151
Expired			(723	)			11.400								19
Outstanding at October 31, 2007			852,450				24.537				7.67				27,128
Shares Exercisable			342,527				18.751				6.66				12,882

The aggregate intrinsic value was calculated using the difference between the current market price and the exercise price for only those options that have an exercise price less than the current market price.

9. Operating Segments

The Company is a multinational company that provides sophisticated services and related products to a variety of markets, as well as being a producer of unconventional natural gas for the energy market. Management defines the Company’s operational organizational structure into discrete divisions based on its primary product lines. Each division comprises a combination of individual district offices, which primarily offer similar types of services and serve similar types of markets. The Company’s reportable segments are defined as follows:

Water and Wastewater Infrastructure Division

This division provides a full line of water-related services and products including hydrological studies, site selection, well design, drilling and development, pump installation, and well rehabilitation. The division’s offerings include the design and construction of water treatment facilities and the provision of filter media and membranes to treat volatile organics and other contaminants such as nitrates, iron, manganese, arsenic, radium and radon in groundwater. The division also offers environmental services to assess and monitor groundwater contaminants. With the acquisition of CWI in June 2006 and UIG in November 2006, the division expanded its capabilities in the area of the design and build of water and wastewater treatment plants, Ranney collector wells, sewer rehabilitation and water and wastewater transmission lines.

Mineral Exploration Division

This division provides a complete range of drilling services for the mineral exploration industry. Its aboveground and underground drilling activities include all phases of core drilling, diamond, reverse circulation, dual tube, hammer and rotary air-blast methods.

Energy Division

This division focuses on exploration and production of unconventional gas properties in the United States. To date this division has primarily been concentrating on projects in the mid-continent region of the United States.

Other

Other includes two small specialty energy service companies and any other specialty operations not included in one of the other divisions.

Financial information (in thousands) for the Company’s operating segments is presented below. Intersegment revenues, if any, are accounted for based on the fair market value of the services provided. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all operating segments. These costs include accounting, financial reporting, internal audit, safety, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer and general counsel) and board of directors.

		Three Months Ended								Nine Months Ended
		October 31,								October 31,
		2007				2006				2007				2006
Revenues
Water and wastewater infrastructure		$	162,255			$	136,586			$	475,604			$	387,607
Mineral exploration			47,380				39,749				130,885				111,615
Energy			10,054				6,814				29,007				17,803
Other			5,537				2,675				9,189				12,662
Total revenues		$	225,226			$	185,824			$	644,685			$	529,687
Equity in earnings of affiliates mineral exploration		$	2,157			$	1,388			$	6,027			$	2,892
Income before income taxes and minority interest
Water and wastewater infrastructure		$	10,647			$	10,015			$	34,422			$	27,423
Mineral exploration			9,033				7,789				26,075				19,963
Energy			3,263				2,362				9,834				6,340
Other			2,872				829				3,477				3550
Unallocated corporate expenses			(5,760	)			(4,230	)			(16,653	)			(13,448	)
Interest			(2,517	)			(2,551	)			(7,744	)			(7,180	)
Total income before income taxes and minority interest		$	17,538			$	14,214			$	49,411			$	36,648
Geographic Information
Revenue
United States		$	182,125			$	151,403			$	530,234			$	425,392
Africa/Australia			23,027				20,054				64,770				60,219
Mexico			11,453				9,423				30,116				23,934
Other foreign			8,621				4,944				19,565				20,142
Total revenues		$	225,226			$	185,824			$	644,685			$	529,687

10. Contingencies

The Company’s drilling activities involve certain operating hazards that can result in personal injury or loss of life, damage and destruction of property and equipment, damage to the surrounding areas, release of hazardous substances or wastes and other damage to the environment, interruption or suspension of drill site operations and loss of revenues and future business. The magnitude of these operating risks is amplified when the Company, as is frequently the case, conducts a project on a fixed-price, “turnkey” basis where the Company delegates certain functions to subcontractors but remains responsible to the customer for the subcontracted work. In addition, the Company is exposed to potential liability under foreign, federal, state and local laws and regulations, contractual indemnification agreements or otherwise in connection with its services and products. Litigation arising from any such occurrences may result in the Company being named as a defendant in lawsuits asserting large claims. Although the Company maintains insurance protection that it considers economically prudent, there can be no assurance that any such insurance will be sufficient or effective under all circumstances or against all claims or hazards to which the Company may be subject or that the Company will be able to continue to obtain such insurance protection. A successful claim or damage resulting from a hazard for which the Company is not fully insured could have a material adverse effect on the Company. In addition, the Company does not maintain political risk insurance with respect to its foreign operations.

The Company is involved in various matters of litigation, claims and disputes which have arisen in the ordinary course of the Company’s business. The Company believes that the ultimate disposition of these matters will not, individually and in the aggregate, have a material adverse effect upon its business or consolidated financial position, results of operations or cash flows.

Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition

Cautionary Language Regarding Forward-Looking Statements

This Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act of 1934. Such statements may include, but are not limited to, statements of plans and objectives, statements of future economic performance and statements of assumptions underlying such statements, and statements of management’s intentions, hopes, beliefs, expectations or predictions of the future. Forward looking statements can often be identified by the use of forward-looking terminology, such as “should,” “intended,” “continue,” “believe,” “may,” “hope,” “anticipate,” “goal,” “forecast,” “plan,” “estimate” and similar words or phrases. Such statements are based on current expectations and are subject to certain risks, uncertainties and assumptions, including but not limited to prevailing prices for various commodities, unanticipated slowdowns in the Company’s major markets, the risks and uncertainties normally incident to the construction industry and exploration for and development and production of oil and gas, the impact of competition, the effectiveness of operational changes expected to increase efficiency and productivity, worldwide economic and political conditions and foreign currency fluctuations that may affect worldwide results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially and adversely from those anticipated, estimated or projected. These forward-looking statements are made as of the date of this filing, and the Company assumes no obligation to update such forward-looking statements or to update the reasons why actual results could differ materially from those anticipated in such forward-looking statements.

Results of Operations

The following table presents, for the periods indicated, the percentage relationship which certain items reflected in the Company’s consolidated statements of income bear to revenues and the percentage increase or decrease in the dollar amount of such items period to period.

																		Period-to-Period
		Three Months								Nine Months								Change
		Ended October 31,								Ended October 31,								Three				Nine
		2007				2006				2007				2006				Months				Months
Revenues:
Water and wastewater infrastructure			72.0	%			73.5	%			73.8	%			73.2	%			18.8	%			12.7	%
Mineral exploration			21.0	%			21.4				20.3				21.1				19.2				17.3
Energy			4.5				3.7				4.5				3.4				47.5				62.9
Other			2.5				1.4				1.4				2.3				107.0				(27.4	)
Total net revenues			100.0	%			100.0	%			100.0	%			100.0	%			21.2				21.7
Cost of revenues			73.2	%			72.9				73.3				73.9				21.7				20.6
Selling, general and administrative expenses			14.0				14.4				14.0				14.2				17.7				19.5
Depreciation, depletion and amortization			5.0				4.7				5.0				4.4				29.5				38.0
Other income (expense):
Equity in earnings of affiliates			1.0				0.7				0.9				0.5				55.4				108.4
Interest			(1.1	)			(1.4	)			(1.2	)			(1.4	)			(1.3	)			7.9
Other, net			0.1				0.4				0.1				0.3				46.0				(40.8	)
Income before income taxes			7.8				7.7				7.7				6.9				23.4				34.8
Income tax expense			3.4				3.5				3.4				3.2				19.2				28.1
Net income			4.4	%			4.2	%			4.3	%			3.7	%			27.9				41.1

Revenues, equity in earnings of affiliates and income before income taxes pertaining to the Company’s operating segments are presented below. Intersegment revenues, if any are accounted for based on the fair market value of the services provided. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all operating segments. These costs include accounting, financial reporting, internal audit, safety, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer and general counsel), and board of directors. Operating segment revenues and income before income taxes are summarized as follows (in thousands):

		Three Months Ended								Nine Months Ended
		October 31,								October 31,
		2007				2006				2007				2006
Revenues
Water and wastewater infrastructure		$	162,255			$	136,586			$	475,604			$	387,607
Mineral exploration			47,380				39,749				130,885				111,615
Energy			10,054				6,814				29,007				17,803
Other			5,537				2,675				9,189				12,662
Total revenues		$	225,226			$	185,824			$	644,685			$	529,687
Equity in earnings of affiliates mineral exploration		$	2,157			$	1,388			$	6,027			$	2,892
Income before income taxes and minority interest
Water and wastewater infrastructure		$	10,647			$	10,015			$	34,422			$	27,423
Mineral exploration			9,033				7,789				26,075				19,963
Energy			3,263				2,362				9,834				6,340
Other			2,872				829				3,477				3,550
Unallocated corporate expenses			(5,760	)			(4,230	)			(16,653	)			(13,448	)
Interest			(2,517	)			(2,551	)			(7,744	)			(7,180	)
Total income before income taxes and minority interest		$	17,538			$	14,214			$	49,411			$	36,648

Revenues for the three months ended October 31, 2007 increased $39,402,000, or 21.2%, to $225,226,000 while revenues for the nine months ended October 31, 2007 increased $114,998,000, or 21.7%, to $644,685,000 from the same periods last year. Revenues were up across all divisions with the main increase in the water and wastewater infrastructure division, including the impact of the acquisitions of American Water Services Underground Infrastructure Inc. (“UIG”) in November 2006 and Collector Wells International Inc. (“CWI”) in June 2006. A further discussion of results of operations by division is presented below.

Selling, general and administrative expenses were $31,457,000 and $89,977,000 for the three and nine months ended October 31, 2007, compared to $26,724,000 and $75,324,000 for the same periods last year. The increases for the three and nine months ended October 31, 2007, respectively, were primarily the result of $1,457,000 and $4,807,000 in expenses added from the acquisitions of UIG and CWI, wage and benefit increases of $1,214,000 and $3,971,000 and share based compensation increases of $347,000 and $478,000. Although down slightly for the three months ended October 31, 2007 incentive compensation expense contributed $2,227,000 to the increase for the nine months ended.

Depreciation, depletion and amortization were $11,228,000 and $31,927,000 for the three and nine months ended October 31, 2007, compared to $8,673,000 and $23,139,000 for the same periods last year. The increases for the three and nine months ended October 31, 2007, respectively, were primarily the result of increased depletion of $881,000 and $3,360,000 from the Company’s energy operations and increased depreciation from property additions and acquisitions in the other divisions.

Equity in earnings of affiliates was $2,157,000 and $6,027,000 for the three and nine months ended October 31, 2007, compared to $1,388,000 to $2,892,000, for the same periods last year. The increases reflect continued strong performance in mineral exploration by affiliates in Latin America and, for the nine months, the absence of inclement weather which affected their results in the early months of the prior year.

Interest expense was $2,517,000 and $7,744,000 for the three and nine months ended October 31, 2007, compared to $2,551,000 and $7,180,000 for same periods last year. The increase for the nine months was primarily a result of increases in the Company’s average borrowings from the prior year in conjunction with the financing of the UIG and CWI acquisitions.

Income tax expense was recorded at an effective tax rate of 43.8% and 44.2% for the three and nine months ended October 31, 2007 compared to an effective rate of 45.4% and 46.5% for the same periods last year. The improvement in the effective rates was primarily attributable to an increase in pre-tax earnings, especially in international operations, and the resolution of certain tax contingencies. The effective rates in excess of the statutory federal rate for the periods were due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.

Water and Wastewater Infrastructure Division
(in thousands)

		Three months ended								Nine months ended
		October 31,								October 31,
		2007				2006				2007				2006
Revenues		$	162,255			$	136,586			$	475,604			$	387,607
Income before income taxes			10,647				10,015				34,422				27,423

Water and wastewater infrastructure revenues increased 18.8% to $162,255,000 and 22.7% to $475,604,000 for the three and nine months ended October 31, 2007, compared to $136,586,000 and $387,607,000 for the same periods last year. The increase in revenues for the three months ended was primarily due to the increases from the UIG acquisition of $11,721,000, year over year improvement in collector well revenues following the CWI acquisition of $4,825,000, and increases in revenue from wastewater infrastructure projects in the southeastern United States of $9,160,000. The increase in revenues for the nine months ended was primarily due to increases from the UIG and CWI acquisitions of $39,984,000, increases in collector well revenues of $4,825,000 following the acquisition and increases in revenues from certain wastewater infrastructure projects in the southeastern United States of $22,291,000.

Income before income taxes for the water and wastewater infrastructure division increased 6.3% to $10,647,000 and 25.5% to $34,422,000 for the three and nine months ended October 31, 2007, respectively, compared to $10,015,000 and $27,423,000 for the same periods last year. The increase in income before income taxes for the three months ended was primarily due to the increases from the UIG acquisition of $1,036,000 and improvement in collector well income following the CWI acquisition of approximately $1,400,000, offset by decreased earnings of $2,200,000 from certain large wastewater plant projects in the southeastern United States which are nearing completion. The increase in income before income taxes for the nine months ended was primarily due to increases from the UIG and CWI acquisitions of $2,166,000, increased earnings from certain of the wastewater projects in the southeastern United States of $2,948,000 and recovery of previously written off costs of $1,626,000 associated with a ground water transfer project in Texas.

The backlog in the water and wastewater infrastructure division was $376,506,000 as of October 31, 2007, compared to $306,939,000 as of October 31, 2006.

Mineral Exploration Division
(in thousands)

		Three months ended								Nine months ended
		October 31,								October 31,
		2007				2006				2007				2006
Revenues		$	47,380			$	39,749			$	130,885			$	111,615
Income before income taxes			9,033				7,789				26,075				19,963

Mineral exploration revenues increased 19.2% to $47,380,000 and 17.3% to $130,885,000 for the three and nine months ended October 31, 2007, respectively, compared to $39,749,000 and $111,615,000 for the same periods last year. The increases were primarily attributable to continued strength in the Company’s markets due to relatively high gold and base metal prices.

Income before income taxes for the mineral exploration division increased 16.0% to $9,033,000 and 30.6% to $26,075,000 for the three and nine months ended October 31, 2007, respectively, compared to $7,789,000 and $19,963,000 for the same periods last year. The improved earnings in the division were primarily attributable to continued strength in the Company’s markets, especially in North America, and an increase of $769,000 and $3,135,000 in equity earnings of affiliates in Latin America for the three and nine month periods, respectively.

Energy Division
(in thousands)

		Three months ended								Nine months ended
		October 31,								October 31,
		2007				2006				2007				2006
Revenues		$	10,054			$	6,814			$	29,007			$	17,803
Income before income taxes			3,263				2,362				9,834				6,340

Energy revenues increased 47.5% to $10,054,000 and 62.9% to $29,007,000 for the three and nine months ended October 31, 2007, respectively, compared to $6,814,000 and $17,803,000 for the same periods last year. The increases in revenues were primarily attributable to increased production from the Company’s unconventional gas properties.

Income before income taxes for the energy division increased 38.1% to $3,263,000 and 55.1% to $9,834,000 for the three and nine months ended October 31, 2007, respectively, compared to $2,362,000 and $6,340,000 for the same periods last year. The increases in income before income taxes were primarily due to the increase in production noted above.

Other
(in thousands)

		Three months ended								Nine months ended
		October 31,								October 31,
		2007				2006				2007				2006
Revenues		$	5,537			$	2,675			$	9,189			$	12,662
Income before income taxes			2,872				829				3,477				3,550

Included in Other for the three and nine months ended October 31, 2007 was $3,166,000 in revenues associated with two contracts to provide consulting and logistical support for international projects in Canada and Africa. Included in the nine months ended October 31, 2006 was $8,798,000 in revenues associated with a contract to provide equipment and supplies to an international oil exploration company. Excluding the effect of these activities, the remainder of the operations included in this segment were consistent period over period.

Unallocated Corporate Expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $5,760,000 and $16,653,000 for the three and nine months ended October 31, 2007, respectively, compared to $4,230,000 and $13,448,000 for the same periods last year. The increases for the periods were primarily due to wage and benefit increases of $272,000 and $806,000, increased incentive compensation of $102,000 and $517,000, increased compensation to directors of $262,000 and $521,000, and increased share based compensation to employees of $347,000 and $478,000.

Changes in Financial Condition

Management exercises discretion regarding the liquidity and capital resource needs of its business segments. This includes the ability to prioritize the use of capital and debt capacity, to determine cash management policies and to make decisions regarding capital expenditures.

The Company maintains an agreement (the “Master Shelf Agreement”) whereby it has $105,000,000 of unsecured notes available to be issued before September 15, 2009. At October 31, 2007, the Company had $60,000,000 in notes outstanding under the Master Shelf Agreement. Additionally, the Company holds a revolving credit facility (the “Credit Agreement”) composed of an unsecured $200,000,000 revolving facility, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit). At October 31, 2007, the Company had no outstanding balance under the Credit Agreement (see Note 4 of the Notes to Consolidated Financial Statements). The Company was in compliance with its financial covenants at October 31, 2007 and expects to remain in compliance through the foreseeable future.

The Company’s working capital as of October 31, 2007 and October 31, 2006 was $137,381,000 and $63,267,000, respectively. Working capital as of October 31, 2007 was unusually high due to remaining proceeds from the Company’s

October stock offering held in commercial paper.

The Company believes it will have sufficient cash from operations and access to credit facilities to meet the Company’s operating cash requirements and to fund its budgeted capital expenditures and acquisitions for fiscal 2008.

Operating Activities

Cash provided by operating activities was $50,452,000 for the nine months ended October 31, 2007 as compared to cash provided by operating activities of $55,564,000 for the nine months ended October 31, 2006. Increased cash from improved earnings was offset by greater growth in working capital.

Investing Activities

The Company’s capital expenditures, net of disposals, of $52,850,000 for the nine months ended October 31, 2007, were directed toward equipment upgrades and capacity increases in the water and wastewater infrastructure division and the Company’s expansion into unconventional gas exploration and production. Expenditures related to the Company’s unconventional gas efforts totaled $21,037,000 for the nine months ended October 31, 2007, including the construction of gas pipeline infrastructure near the Company’s development projects.

On November 30, 2007, the Company acquired certain assets of SolmeteX, Inc., a wastewater treatment company, for approximately $13,500,000.

Financing Activities

For the nine months ended October 31, 2007, the Company had net repayments of $91,600,000 under its credit facilities, which are primarily used to fund capital expenditures. The outstanding balance of the Company’s Credit Agreement was repaid when the Company completed a public stock offering of 3,105,000 common shares in October 2007. Proceeds of the offering, net of issuance cost of $9,344,000, were $159,879,000.

The Company’s contractual obligations and commercial commitments as of October 31, 2007, are summarized as follows (in thousands):

		Payments/Expiration by Period
						Less than												More than
		Total				1 year				1-3 years				4-5 years				5 years
Contractual obligations and other commercial commitments
Senior Notes		$	60,000			$	13,333			$	20,000			$	26,667			$	—
Credit Agreement			—				—				—				—				—
Operating leases			31,412				13,083				11,632				4,455				2,242
Mineral interest obligations			608				114				230				235				29
Total contractual cash obligations			92,020				26,530				31,862				31,357				2,271
Standby letters of credit			13,717				13,717				—				—				—
Asset retirement obligations			864				—				—				—				864
Total contractual obligations and commercial commitments		$	106,601			$	40,247			$	31,862			$	31,357			$	3,135

The Company expects to meet its contractual cash obligations in the ordinary course of operations, and that the standby letters of credit will be renewed in connection with its annual insurance renewal process. Payments related to the Credit Agreement and Senior Notes do not include interest payments. Interest is payable on the Senior Notes at fixed interest rates of 6.05% and 5.40%. Interest is payable on the Credit Agreement at variable interest rates equal to, at the Company’s option, a LIBOR rate plus 0.75% to 2.00%, or a base rate, as defined in the Credit Agreement plus up to 0.50%, depending on the Company’s leverage ratio (See Note 4 of the Notes to Consolidated Financial Statements).

The Company incurs additional obligations in the ordinary course of operations. These obligations, including but not limited to, interest payments on debt, income tax payments and pension fundings are expected to be met in the normal course of operations.

Critical Accounting Policies and Estimates

Management’s Discussion and Analysis of Financial Condition and Results of Operations discusses the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an on-going basis, management evaluates its estimates and judgments, which are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

Our accounting policies are more fully described in Note 1 of the Notes to Consolidated Financial Statements, located in Item 1 of this Form 10-Q. We believe that the following represent our more critical estimates and assumptions used in the preparation of our consolidated financial statements, although not all inclusive.

Revenue Recognition — Revenues are recognized on large, long-term construction contracts meeting the criteria of Statement of Position 81-1, Accounting for Performance of Construction-Type and Certain Production-Type Contracts (“SOP 81-1”), using the percentage-of-completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. As allowed by SOP 81-1, revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.

Revenues for direct sales of equipment and other ancillary products not provided in conjunction with the performance of construction contracts are recognized at the date of delivery to, and acceptance by, the customer. Provisions for estimated warranty obligations are made in the period in which the sales occur.

Contracts for the Company’s mineral exploration drilling services are billable based on the quantity of drilling performed. Thus, revenues for these drilling contracts are recognized on the basis of actual footage or meterage drilled.

Revenues for the sale of oil and gas by the Company’s energy division are recognized on the basis of volumes sold at the time of delivery to an end user or an interstate pipeline, net of amounts attributable to royalty or working interest holders.

The Company’s revenues are presented net of taxes imposed on revenue-producing transactions with its customers, such as, but not limited to, sales, use, value-added, and some excise taxes.

Oil and gas properties and mineral interests — The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, and salaries, benefits and other internal salary-related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.

The Company is required to review the carrying value of its oil and gas properties each quarter under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and gas properties, as adjusted for asset retirement obligations, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenues at the unescalated prices in effect as of the last day of the period, with effect given to the Company’s fixed-price physical delivery contracts, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.

Reserve Estimates — The Company’s estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.

Goodwill and Other Intangibles —The Company accounts for goodwill and other intangible assets in accordance with the Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. Other intangible assets primarily consist of trademarks, customer-related intangible assets and patents obtained through business acquisitions. Amortizable intangible assets are being amortized over their estimated useful lives, which range from one to 40 years.

The impairment evaluation for goodwill is conducted annually, or more frequently, if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

The impairment evaluation of the carrying amount of intangible assets with indefinite lives is conducted annually or more frequently if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by comparing the carrying amount of these assets to their estimated fair value. If the estimated fair value is less than the carrying amount of the intangible assets with indefinite lives, then an impairment charge is recorded to reduce the asset to its estimated fair value. The estimated fair value is generally determined on the basis of discounted future cash flows.

The assumptions used in the estimate of fair value are generally consistent with the past performance of each reporting unit and are also consistent with the projections and assumptions that are used in current operating plans. Such assumptions are subject to change as a result of changing economic and competitive conditions.

Other Long-lived Assets — In the event of an indication of possible impairment, the Company evaluates the fair value and future benefits of long-lived assets, including the Company’s gas transportation facilities and equipment, by performing an analysis of the anticipated future net cash flows of the related long-lived assets. In the event of an impairment the carrying value of these assets would be reduced to fair value. The Company believes at this time that the carrying values and useful lives of its long-lived assets continue to be appropriate.

Accrued Insurance Expense — The Company maintains insurance programs where it is responsible for a certain amount of each claim up to a self-insured limit. Estimates are recorded for health and welfare, property and casualty insurance costs that are associated with these programs. These costs are estimated based on actuarially determined projections of future payments under these programs. Should a greater amount of claims occur compared to what was estimated or medical costs increase beyond what was anticipated, reserves recorded may not be sufficient and additional costs to the consolidated financial statements could be required.

Costs estimated to be incurred in the future for employee medical benefits, property, workers’ compensation and casualty insurance programs resulting from claims which have occurred are accrued currently. Under the terms of the Company’s agreement with the various insurance carriers administering these claims, the Company is not required to remit the total premium until the claims are actually paid by the insurance companies. These costs are not expected to significantly impact liquidity in future periods.

Income Taxes — Income taxes are provided using the asset/liability method, in which deferred taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax assets are reviewed for recoverability and valuation allowances are provided as necessary. Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on those amounts in excess of funds considered to be invested indefinitely.

Due to the breadth of the Company’s international operations, numerous tax examinations may be ongoing throughout the world at any point in time. Tax liabilities are recorded based on estimates of additional taxes which will be due upon the conclusion of these examinations. Estimates of these tax liabilities are made based upon prior experience and are updated in light of changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, examination outcomes and the timing of settlements are subject to significant uncertainty.

Litigation and Other Contingencies — The Company is involved in litigation incidental to its business, the disposition of which is not expected to have a material effect on the Company’s financial position or results of operations. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. The Company accrues its best estimate of the probable cost for the resolution of legal claims. Such estimates are developed in consultation with outside counsel handling these matters and are based upon a combination of litigation and settlement strategies. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

The principal market risks to which the Company is exposed are interest rates on variable rate debt, foreign exchange rates giving rise to translation and transaction gains and losses and fluctuations in the price of natural gas.

The Company centrally manages its debt portfolio considering overall financing strategies and tax consequences. A description of the Company’s debt is in Note 11 of the Notes to Consolidated Financial Statements appearing in the Company’s January 31, 2007 Form 10-K and Note 4 of this Form 10-Q. As of October 31, 2007, $60,000,000 of the Company’s long-term debt outstanding carries a fixed-rate. As all of the Company’s currently outstanding debt bears interest at fixed rates, an instantaneous change in interest rates of one percentage point would have no effect on the Company’s annual interest expense.

Operating in international markets involves exposure to possible volatile movements in currency exchange rates. Currently, the Company’s primary international operations are in Australia, Africa, Mexico and Italy. The operations are described in Note 1 of the Notes to Consolidated Financial Statements appearing in the Company’s January 31, 2007 Form 10-K and Note 9 of this Form 10-Q. The majority of the Company’s contracts in Africa and Mexico are U.S. dollar based, providing a natural reduction in exposure to currency fluctuations. The Company also may utilize various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with fluctuating currency exchange rates.

As currency exchange rates change, translation of the income statements of the Company’s international operations into U.S. dollars may affect year-to-year comparability of operating results. We estimate that a ten percent change in foreign exchange rates would not have significantly impacted income from continuing operations for the three months ended October 31, 2007. This quantitative measure has inherent limitations, as it does not take into account any governmental actions, changes in customer purchasing patterns or changes in the Company’s financing and operating strategies.

The Company is also exposed to fluctuations in the price of natural gas, which result from the sale of the energy division’s unconventional gas production. The price of natural gas is volatile and the Company has entered into fixed-price physical contracts covering a portion of its production to manage price fluctuations and to achieve a more predictable cash flow. As of October 31, 2007, the Company held contracts for physical delivery of 5,018,000 million British Thermal Units (“MMBtu”) of natural gas through March 2010 at prices ranging from $7.46 to $9.015 per MMBtu. The estimated fair value of such contracts at October 31, 2007 was $2,821,000. We estimate that a ten percent change in the price of natural gas would have impacted income from continuing operations before taxes by approximately $105,000 for the nine months ended October 31, 2007.

ITEM 4. Controls and Procedures

Based on an evaluation of disclosure controls and procedures for the period ended October 31, 2007, conducted under the supervision and with the participation of the Company’s management, including the Principal Executive Officer and the Principal Financial Officer, the Company concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management (including the Principal Executive Officer and the Principal Financial Officer) to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

Based on an evaluation of internal controls over financial reporting conducted under the supervision and the participation of the Company’s management, including the Principal Executive Officer and the Principal Financial Officer, for the period ended October 31, 2007, the Company concluded that its internal control over financial reporting is effective as of October 31, 2007. The Company has not made any significant changes in internal controls or in other factors that could significantly affect internal controls since such evaluation. The Company excluded from its assessment any changes in internal control over financial reporting at American Water Services Underground Infrastructure, Inc. (“UIG”), which was acquired on November 20, 2006, and whose financial statements reflect total assets and revenues constituting 6% and 5%, respectively, of the related consolidated financial statement amounts as of and for the nine months ended October 31, 2007. The Company will include UIG in its evaluation of the design and effectiveness of internal control over financial reporting as of January 31, 2008.

PART II

ITEM 1 — Legal Proceedings

NONE

ITEM 1A.— Risk Factors

There have been no significant changes to the risk factors disclosed under Item 1A in our Annual Report on Form 10-K for the year ended January 31, 2007.

ITEM 2 — Unregistered Sales of Equity Securities and Use of Proceeds

NOT APPLICABLE

ITEM 3 — Defaults Upon Senior Securities

NOT APPLICABLE

ITEM 4 — Submission of Matters to a Vote of Security Holders

NONE

ITEM 5 — Other Information

NONE

ITEM 6 — Exhibits

3(1)		Corrected Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 filed September 20, 2007).
3(2)		Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1(b) to the Company’s Current Report on Form 8-K filed on September 17, 2007).
10(1)		Amendment No. 3 to Amended and Restated Loan Agreement, dated October 15, 2007, by and among the Company, LaSalle Bank National Association, as Administrative Agent and Lender, and the other Lenders listed therein.
10(2)		Letter Amendment No. 5 to Senior Notes Mater Shelf Agreement, dated October 15, 2007, by and among the Company, Prudential Investment Management, Inc., The Prudential Insurance Company of America, Pruco Life Insurance Company, Security Life of Denver Insurance Company and such other Purchasers of the Notes as may be named therein from time to time.
10(3)		Form of Restricted Stock Award Agreement for Management and Non-Employee Directors under the Company’s 2006 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed September 17, 2007).
31(1)		Section 302 Certification of Chief Executive Officer of the Company.
31(2)		Section 302 Certification of Chief Financial Officer of the Company.
32(1)		Section 906 Certification of Chief Executive Officer of the Company.
32(2)		Section 906 Certification of Chief Financial Officer of the Company.

* * * * * * * * * *

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.