SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended April 30, 2006

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

For the transition period from                      to                     

Layne Christensen Company

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

Not Applicable

     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 15,259,016 shares of common stock, $.01 par value per share, outstanding on May 25, 2006.

 

 

PART I

Item 1. Financial Statements

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

		April 30,				January 31,
		2006				2006
		(unaudited)				(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	11,786			$	17,983
Customer receivables, less allowance of $5,723 and $5,573, respectively			98,673				91,159
Costs and estimated earnings in excess of billings on uncompleted contracts			44,157				36,538
Inventories			16,457				16,663
Deferred income taxes			15,301				11,976
Income taxes receivable			200				1,284
Other			4,456				5,975
Total current assets			191,030				181,578
Property and equipment:
Land			9,480				9,486
Buildings			20,586				19,595
Machinery and equipment			225,344				222,531
Gas transportation facilities and equipment			15,856				12,526
Oil and gas properties			39,359				34,308
Mineral interest in oil and gas properties			8,827				8,430
			319,452				306,876
Less — Accumulated depreciation and depletion			(153,605	)			(148,751	)
Net property and equipment			165,847				158,125
Other assets:
Investment in affiliates			21,752				21,741
Goodwill			57,857				57,857
Other intangible assets, net			16,702				16,948
Restricted cash			8,950				9,143
Other			4,324				3,943
Total other assets			109,585				109,632
		$	466,462			$	449,335

See Notes to Consolidated Financial Statements.

— Continued -

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

		April 30,				January 31,
		2006				2006
		(unaudited)				(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	45,183			$	43,695
Accrued compensation			14,291				20,025
Cash purchase price adjustments			—				6,120
Accrued insurance expense			6,274				5,562
Other accrued expenses			17,836				12,212
Income taxes payable			5,891				2,606
Billings in excess of costs and estimated earnings on uncompleted contracts			19,074				21,362
Total current liabilities			108,549				111,582
Noncurrent and deferred liabilities:
Long-term debt			141,200				128,900
Acquisition escrow obligations			9,164				9,143
Accrued insurance expense			6,340				6,228
Deferred income taxes			21,656				19,555
Other			2,367				2,301
Total noncurrent and deferred liabilities			180,727				166,127
Common stock, par value $.01 per share, 30,000,000 shares authorized, 15,259,016 and 15,233,472 shares issued and outstanding, respectively			153				152
Capital in excess of par value			141,922				141,067
Retained earnings			42,535				37,893
Accumulated other comprehensive loss			(7,397	)			(7,442	)
Unearned compensation			(27	)			(44	)
Total stockholders’ equity			177,186				171,626
		$	466,462			$	449,335

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
		Ended April 30,
		(unaudited)
		2006				2005
Revenues		$	156,717			$	96,658
Cost of revenues (exclusive of depreciation shown below)			117,037				71,080
Gross profit			39,680				25,578
Selling, general and administrative expenses			22,364				16,890
Depreciation, depletion and amortization			7,066				4,013
Other income (expense):
Equity in earnings of affiliates			365				1,119
Interest			(2,131	)			(970	)
Other income, net			274				520
Income from continuing operations before income taxes and minority interest			8,758				5,344
Income tax expense			4,116				2,567
Minority interest			—				(23	)
Net income from continuing operations before discontinued operations			4,642				2,754
Loss from discontinued operations, net of income tax			—				(1	)
Net income		$	4,642			$	2,753
Basic income per share:
Net income from continuing operations		$	0.30			$	0.22
Loss from discontinued operations, net of income taxes			—				—
Net income per share		$	0.30			$	0.22
Diluted income per share:
Net income from continuing operations		$	0.30			$	0.21
Loss from discontinued operations, net of income taxes			—				—
Net income per share		$	0.30			$	0.21
Weighted average shares outstanding			15,233,000				12,595,000
Dilutive stock options			222,000				405,000
			15,455,000				13,000,000

See Notes to Consolidated Financial Statements.

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

		Three Months
		Ended April 30,
		(unaudited)
		2006				2005
Cash flow used in operating activities:
Net income		$	4,642			$	2,753
Adjustments to reconcile net income to cash from operations:
Loss from discontinued operations, net of tax			—				1
Depreciation, depletion and amortization			7,066				4,013
Deferred income taxes			(1,125	)			(595	)
Share-based compensation			454				—
Equity in earnings of affiliates			(365	)			(1,119	)
Dividends received from affiliates			354				354
Minority interest			—				23
Gain from disposal of property and equipment			(113	)			(443	)
Changes in current assets and liabilities, net of effects of acquisitions:
Increase in customer receivables			(7,453	)			(11,631	)
Increase in costs and estimated earnings in excess of billings on uncompleted contracts			(7,619	)			(2,373	)
(Increase) decrease in inventories			273				(2,258	)
Decrease in other current assets			1,529				208
Increase in accounts payable and accrued expenses			375				4,689
Decrease in billings in excess of costs and estimated earnings on uncompleted contracts			(2,288	)			(970	)
Other, net			13				46
Cash used in continuing operations			(4,257	)			(7,302	)
Cash from discontinued operations			—				25
Cash used in operating activities			(4,257	)			(7,277	)
Cash flow used in investing activities:
Additions to property and equipment			(5,760	)			(4,368	)
Additions to gas transportation facilities and equipment			(3,330	)			(93	)
Additions to oil and gas properties			(5,051	)			(1,261	)
Additions to mineral interests in oil and gas properties			(397	)			(189	)
Proceeds from disposal of property and equipment			133				515
Cash used in investing activities			(14,405	)			(5,396	)
Cash flow from financing activities:
Borrowings under revolving credit facility			79,900				12,100
Repayments under revolving credit facility			(67,600	)			(6,800	)
Payments on DrillCorp promissory note			—				(360	)
Excess tax benefit on exercise of share-based instruments			154				—
Issuance of common stock upon exercise of stock options			198				12
Cash from financing activities			12,652				4,952
Effects of exchange rate changes on cash			(187	)			(56	)
Net decrease in cash and cash equivalents			(6,197	)			(7,777	)
Cash and cash equivalents at beginning of period			17,983				14,408
Cash and cash equivalents at end of period		$	11,786			$	6,631

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 intercompany 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, 2006 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 — Revenue is recognized on large, long-term contracts 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 and gross profit 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. Revenue is recognized on smaller, short-term contracts using the completed contract method. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined.

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. 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 evaluating the fair value and future benefits of long-lived assets, including the Company’s gas transportation facilities and equipment, the Company performs an analysis of the anticipated future net cash flows of the related long-lived assets and reduces their carrying value by the excess, if any, of the result of such calculation. The Company believes at this time that the carrying values and useful lives of its long-lived assets continues to be appropriate.

Restricted Cash - Included in restricted cash as of April 30, 2006 are escrow funds associated with the acquisition of Reynolds as described in Note 2 of the Notes to Consolidated Financial Statements of $5,102,000 and customer deposits held by the bank of $4,062,000.

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.

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 unconventional 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 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.

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 6 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.

Unearned Compensation – Unearned compensation expense associated with the issuance of restricted stock is amortized on a straight-line basis as the restrictions on the stock expire.

Stock-based compensation – The Company adopted SFAS No. 123R (revised December 2004), “Shared-Based Payment” 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 has elected to adopt the new 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. An expense of $454,000 was recognized in the three months ended April 30, 2006, as a result of the adoption of this method. The total income tax benefit recognized in the three months ended April 30, 2006 was $203,000. The Modified Prospective Method has no financial impact on prior fiscal years. As of April 30, 2006, the Company had unrecognized compensation expense of $5,631,000 to be recognized over a weighted average period of 3.24 years. The Company determines the fair value of stock-based compensation using the Black-Scholes model.

Stock-based compensation vested prior to the effective date of SFAS No. 123R may be accounted for either based on the estimated fair value of the awards at the date they are granted (the “SFAS 123 Method”) or based on the difference, if any, between the market price of the stock at the date of grant and the amount the employee must pay to acquire the stock (the “APB 25 Method”). The Company used the APB 25 Method to account for its stock-based compensation programs that were vested prior to the effective date of SFAS No. 123R and recognized no compensation expense under this method.

Pro forma net income and earnings per share for the three months ended April 30, 2005, determined as if the SFAS No. 123 Method had been applied, is presented in the following table (in thousands, except per share amounts):

		2005
Net income, as reported		$	2,753
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards not yet recognized, net of tax			(114	)
Pro forma net income		$	2,639
Income per share:
Basic — as reported		$	0.22
Basic — pro forma		$	0.21
Diluted — as reported		$	0.21
Diluted — pro forma		$	0.20

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 are as follows (in thousands):

		Three Months
		Ended April 30,
		2006				2005
Income taxes		$	773			$	972
Interest			1,414				351

2. Acquisitions

On September 28, 2005 (the “Closing Date”), the Company acquired 100% of the outstanding stock of Reynolds, Inc. (“Reynolds”), a privately held company and a major supplier of products and services to the water and wastewater industries. The acquisition will expand the capabilities of the Company in the areas of water and wastewater infrastructure. Reynolds’ primary service lines include designing and building of water and wastewater treatment plants, water and wastewater transmission lines, cured in place pipe (“CIPP”) services for sewer rehabilitation, water supply wells and Ranney collector wells.

The purchase price for Reynolds was $112,356,000, consisting of $60,000,000 cash, 2,222,216 shares of Layne common stock (valued at $45,053,000), cash purchase price adjustments of $6,120,000 and costs of $1,183,000. 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 terms of the acquisition were agreed to and publicly announced. Of the cash and stock consideration, $9,000,000 and 333,333 shares of Layne common stock were placed in escrow to secure certain representations, warranties and indemnifications under the purchase agreement (the “Escrow Fund”). The cash purchase price adjustments consist primarily of an adjustment based on the amount by which working capital at the Closing Date exceeded a threshold amount established in the purchase agreement. Pursuant to the purchase agreement, this amount was paid to the Reynolds shareholders during April 2006 from the Escrow Fund, which will be replenished during the twenty-four months following the Closing Date based on the collection of certain contract retainage amounts. The balance of the Escrow Fund will be released to the Reynolds shareholders twenty four months following the Closing Date, subject to any pending claims. The cash portion of the Escrow Fund and related obligations to the Reynolds’ shareholders are recorded in the Company’s consolidated balance sheet as “Restricted cash” and “Acquisition escrow obligation.”

In addition, there is contingent consideration up to a maximum of $15,000,000 (the “Earnout Amount”), which is based on Reynolds’ operating performance over a period of thirty-six months following the Closing Date (the “Earnout Period”). The Earnout Amount is based on a multiple of Reynolds’ earnings before interest, taxes, depreciation and amortization which exceed a threshold amount during the Earnout Period. If earned, the contingent payment will be paid 60% in cash and 40% in Layne common stock, subject to stockholder approval of the shares to be issued, if required. Any shares not approved for issuance will be paid in cash. Any portion of the 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 Reynolds’ historical cost basis of assets and liabilities, appraisals and other analyses. Such amounts may be subject to revision as Reynolds is integrated into the Company and the revisions may be significant and will be recorded by the Company as further adjustments to the purchase price allocation.

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		$	20,998
Property and equipment			40,508
Goodwill			49,832
Tradenames			16,000
Other intangible assets			586
Deferred income taxes			(15,568	)
Total purchase price		$	112,356

The results of operations of Reynolds have been included in the Company’s consolidated Statements of Income as of the Closing Date. Assuming Reynolds had been acquired as of the beginning of the period, the unaudited proforma 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
		April 30,
		2006				2005
Revenues		$	156,717			$	143,141
Net income from continuing operations			4,642				5,355
Net income			4,642				5,354
Basic earnings per share from continuing operations			0.30				0.36
Diluted earnings per share from continuing operations			0.30				0.35
Basic earnings per share			0.30				0.36
Diluted earnings per share			0.30				0.35

The pro forma information provided above is not necessarily indicative of the results of operations that would actually have resulted if the acquisition were made as of those dates or of results that may occur in the future.

In October 2005, the Company purchased the remaining 25% working interest in various gas wells, saltwater disposal wells and a pipeline from Colt Natural Gas LLC and Colt Pipeline LLC (“Colt”), which are affiliates of a working interest partner, for $6,149,000 in cash. An additional $257,000 is payable by the Company upon satisfaction of certain conditions by Colt. The acquisition furthers the Company’s expansion of its energy presence in the mid-continent region of the United States. The acquisition did not have a significant effect on the Company’s results of operations or cash flows and had the following effect on the Company’s consolidated financial position (in thousands):

Mineral interest in oil and gas properties		$	2,479
Oil and gas properties			2,428
Gas transportation facilities and equipment			987
Minority interest			512
Total purchase price		$	6,406

The Company made two acquisitions in March and June 2005 to broaden its membrane technologies capabilities. The total purchase price for the acquisitions was $453,000, which consisted of cash payments of $359,000 and a note payable to the shareholder of one of the entities. The acquisitions did not have a significant effect on the Company’s results of operations or cash flows and had the following effect on the Company’s consolidated financial position (in thousands)

Working capital		$	(10	)
Property and equipment			84
Other intangible assets			379
Total purchase price		$	453

3. Discontinued Operations

During the third quarter of fiscal 2004, the Company reclassified the results of operations of its Toledo Oil and Gas (“Toledo”) business to discontinued operations based on its intent to sell the operation, which occurred in January 2004. Toledo was historically reported in the Company’s energy segment and offered conventional oilfield fishing services and coil tubing fishing services.

On January 30, 2004, the Company sold its Layne Christensen Canada Ltd. (“Layne Canada”) subsidiary for $15,914,000. Layne Canada was a component of the Company’s energy segment and provided drilling services to the shallow, unconventional oil and gas market.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the results of operations for Toledo and Layne Canada have been classified as discontinued operations. The discontinued operations had no revenue for the three months ended April 30, 2006 or 2005. The loss from discontinued operations before income taxes was $1,000 for the three months ended April 30, 2005.

4. Goodwill and Other Intangible Assets

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

		April 30, 2006												January 31, 2006
										Weighted												Weighted
										Average												Average
		Gross								Amortization				Gross								Amortization
		Carrying				Accumulated				Period in				Carrying				Accumulated				Period in
		Amount				Amortization				years				Amount				Amount				years
Goodwill (non-tax deductible)		$	57,857			$	—							$	57,857			$	—
Other amortizable intangible assets
Tradenames		$	16,000			$	(358	)			32			$	16,000			$	(204	)			32
Customer-related			227				(59	)			2				227				(34	)			2
Patents			359				(70	)			3				359				(40	)			3
Non-competition agreements			379				(77	)			5				379				(58	)			5
Other			730				(429	)			23				730				(411	)			23
Total amortizable intangible assets		$	17,695			$	(993	)						$	17,695			$	(747	)

Amortizable intangible assets are being amortized over their estimated useful lives of two to 40 years with a weighted average amortization period of 30 years. Total amortization expense for other intangible assets was $246,000 and $11,000 for the quarters ended April 30, 2006 and 2005, 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, 2006		$	950			$	56,907			$	57,857
Additions			—				—				—
Balance, April 30, 2006		$	950			$	56,907			$	57,857

5. 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 the acquisition of Beylik and general corporate purposes. Concurrent with the acquisition of Reynolds, the Company amended the Master Shelf Agreement to increase the amount of senior notes available to be issued from $60,000,000 to $100,000,000, thus, creating an available facility amount of $40,000,000, and reinstated and extended the available issuance period to September 15, 2007.

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 $40,000,000 to $130,000,000, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit). Approximately $80 million 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 provides for interest at variable rates equal to, at the Company’s option, a LIBOR rate plus 1.00% 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 September 24, 2010. On April 30, 2006, there were letters of credit of $6,914,000 and borrowings of $81,200,000 outstanding on the Credit Agreement resulting in available capacity of $41,886,000.

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 April 30, 2006.

Debt outstanding as of April 30, 2006 and January 31, 2006 was as follows (in thousands):

		April 30,				January 31,
		2006				2006
Long-term debt:
Credit Agreement		$	81,200			$	68,900
Senior Notes			60,000				60,000
Total long-term debt		$	141,200			$	128,900

6. 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 April 30, 2006, the Company had committed to deliver 4,048,000 million British Thermal Units (“MMBtu”) of natural gas through March 2008. The prices on these contracts range from $8.89 to $9.65 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 April 30, 2006 was $4,025,000.

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 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.

The Company held option contracts with an aggregate U.S. dollar notional value of $8,500,000 as of April 30, 2006 to hedge the risks associated with forecasted Australian dollar denominated costs in its African operations. The contracts settle in various increments through January 2007. The fair value of the instruments of $252,000 at April 30, 2006 was recorded in other current assets and in accumulated other comprehensive income net of income taxes of $98,000. Aggregate losses of $11,000 on foreign currency hedging transactions were recognized for the three months ended April 30, 2006 as the forecasted transactions being hedged occured and were recorded primarily in cost of revenues in the Company’s Consolidated Statements of Income.

7. Other Comprehensive Income (Loss)

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

		Three Months Ended
		April 30,
		2006				2005
Net income		$	4,642			$	2,753
Other comprehensive income (loss),net of taxes:
Foreign currency translation adjustments			(109	)			(133	)
Change in unrecognized pension liability			—				(154	)
Unrealized gain on foreign exchange contracts			154				—
Other comprehensive income		$	4,687			$	2,466

The components of accumulated other comprehensive loss for the three months ended April 30, 2006 and 2005 are as follows (in thousands):

										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			(109	)			—				154				45
Balance, April 30, 2006		$	(7,551	)		$	—			$	154			$	(7,397	)

										Unrealized				Accumulated
		Cumulative				Unrecognized				Gain				Other
		Translation				Pension				on Exchange				Comprehensive
		Adjustment				Liability				Contracts				Loss
Balance, February 1, 2005		$	(7,165	)		$	(1,902	)		$	—			$	(9,067	)
Period change			(133	)			(154	)			—				(287	)
Balance, April 30, 2005		$	(7,298	)		$	(2,056	)		$	—			$	(9,354	)

8. 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 months ended April 30, 2006 and 2005 includes the following components (in thousands):

		Three Months
		Ended April 30,
		2006				2005
Service cost		$	18			$	18
Interest cost			109				109
Expected return on assets			(121	)			(121	)
Net amortization			67				67
Net periodic pension cost		$	73			$	73

The Company has recognized the full amount of its actuarially determined pension liability and the related intangible asset (if applicable). The unrecognized pension cost has been recorded as a charge to consolidated stockholders’ equity after giving effect to the related future tax benefit.

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 months ended April 30, 2006 and 2005 include the following components (in thousands):

		Three Months
		Ended April 30,
		2006				2005
Service cost		$	30			$	30
Interest cost			19				19
Net periodic pension cost		$	49			$	49

9. Stock and Stock Option Plans

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 $.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 reserved 750,000 shares of common stock for issuance under employee incentive compensation plans. Issuance of shares under the plans is based on performance as determined annually at the discretion of a committee appointed by the Company’s Board of Directors.

The Company also has stock option plans that provide for the granting of options to purchase up to an aggregate of 1,250,000 shares of common stock at a price fixed by the Board of Directors or a committee. As of April 30, 2006, there are no shares available to be granted under the stock option plans. The Company has the ability to issue shares under the stock option 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.

Significant option groups outstanding at April 30, 2006, and related exercise price and remaining contractual term follows:

														Remaining
														Contractual
Grant		Options				Options				Exercise				Term
Date		Outstanding				Exercisable				Price				(Months)
4/97			3,264				3,264			$	11.400				12
2/98			125,000				125,000				14.000				21
4/98			5,144				5,144				10.290				24
4/99			9,773				9,773				4.125				36
4/99			153,075				153,075				5.250				36
2/00			3,500				3,500				5.500				46
4/00			16,885				16,885				3.495				48
8/00			2,500				2,500				5.125				52
6/04			30,000				30,000				16.600				99
6/04			267,802				66,955				16.650				99
6/05			14,000				14,000				17.540				111
9/05			250,000				—				23.050				115
1/06			210,231				—				27.870				118
			1,091,174				430,096

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 five to ten years from the date of grant and generally vest ratably over periods of four to five years. Certain option awards provide for accelerated vesting if there is a change of control (as defined in the plans) and for equitable adjustments in the event of changes in the Company’s equity structure. The Company does not expect any unvested shares to be forfeited. Transactions for stock options for the period ended April 30, 2006 were as follows:

		Stock Options
										Weighted
										Average				Aggregate
						Weighted				Remaining				Intrinsic
		Number of				Average				Contractual Term				Value
		Options				Exercise Price				(years)				(in thousands)
Stock Option Activity Summary:
Outstanding at February 1, 2006			1,116,718			$	17.728
Granted			—				—
Exercised			(25,544	)			7.740							$	539
Canceled			—				—
Forfeited			—				—
Expired			—				—
Outstanding at April 30, 2006			1,091,174			$	17.960				7.21			$	12,590
Shares Exercisable			430,096			$	10.770				4.05			$	8,054

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 prices.

10. 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. Should an office’s primary responsibility move from one division president to another, that office’s results going forward would be reclassified between divisions at that time. 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 well development, pump installation, and repair and maintenance. The division’s offerings include the design and construction of water treatment facilities and the manufacture and sale of products 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 Reynolds in September 2005, 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.

Effective February 1, 2006, the Company’s Geoconstruction division, previously a separate segment, was reorganized under the operational leadership of the water and wastewater infrastructure division. The Company’s segment disclosures for all periods have been reorganized accordingly for comparative purposes. This division focuses on services that improve soil stability, primarily jet grouting, grouting, vibratory ground improvement, drilled micropiles, stone columns, anchors and tiebacks. The division also manufactures a line of high-pressure pumping equipment used in grouting operations and geotechnical drilling rigs used for directional drilling.

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 entirely on exploration and production of unconventional gas properties in the United States. To date this division has been concentrated on projects in the mid-continent region of the United States. Historically, the division has also included service businesses in shallow gas and tar sands exploration drilling, conventional oilfield fishing services and coil tubing fishing services. In fiscal 2006, the division completed its shift in focus to unconventional gas development activities and has reclassified the results of all other service operations to the “Other” division.

Other

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

Revenues and income from continuing operations pertaining to the Company’s operating segments are presented below (in thousands). Intersegment revenues 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. Beginning February 1, 2006, corporate expenses also include expenses associated with share-based payments.

		Three Months Ended
		April 30,
		2006				2005
Revenues
Water and wastewater infrastructure		$	116,695			$	63,667
Mineral exploration			33,628				30,559
Energy			5,064				1,778
Other			1,330				654
Total revenues		$	156,717			$	96,658
Equity in earnings of affiliates
Mineral exploration		$	365			$	792
Water and wastewater infrastructure			—				327
Total equity in earnings of affiliates		$	365			$	1,119
Income from continuing operations before income taxes and minority interest
Water and wastewater infrastructure		$	7,983			$	5,526
Mineral exploration			4,985				4,128
Energy			2,057				68
Other			305				10
Unallocated corporate expenses			(4,441	)			(3,418	)
Interest			(2,131	)			(970	)
Total income from continuing operations before income taxes and minority interest		$	8,758			$	5,344
Geographic Information:
Revenues
United States		$	125,929			$	69,104
Africa/Australia			18,993				19,126
Mexico			6,590				4,863
Other foreign			5,205				3,565
Total revenues		$	156,717			$	96,658

11. 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 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, 2006.

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,” “will,” “will be,” “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.

		Three Months Ended								Period-to-Period
		April 30,								Change
		2006				2005				Three Months
Revenues:
Water and wastewater infrastructure			74.5	%			65.9	%			83.3	%
Mineral exploration			21.5				31.6				10.0
Energy			3.2				1.8				184.8
Other			0.8				0.7				103.4
Total net revenues			100.0	%			100.0	%			62.1
Cost of revenues			74.7	%			73.5	%			64.7
Gross profit			25.3				26.5				55.1
Selling, general and administrative expenses			14.3				17.5				32.4
Depreciation, depletion and amortization			4.5				4.2				76.1
Other income (expense):
Equity in earnings of affiliates			0.2				1.2				(67.4	)
Interest			(1.4	)			(1.0	)			119.7
Other, net			0.3				0.5				(47.3	)
Income from continuing operations before income taxes and minority interest			5.6				5.5				63.9
Income tax expense			2.6				2.7				60.3
Minority interest			0.0				0.0				*
Net income from continuing operations before discontinued operations			3.0				2.8				68.6
Loss from discontinued operations, net of tax			0.0				0.0				*
Net income			3.0	%			2.8	%			68.6	%

Revenues and income from continuing operations pertaining to the Company’s operating segments are presented below. Intersegment revenues 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. Beginning February 1, 2006, corporate expenses also include expenses associated with share-based payments. Operating segment revenues and income from continuing operations are summarized as follows (in thousands):

		Three Months Ended
		April 30,
		2006				2005
Revenues
Water and wastewater infrastructure		$	116,695			$	63,667
Mineral exploration			33,628				30,559
Energy			5,064				1,778
Other			1,330				654
Total revenues		$	156,717			$	96,658
Equity in earnings of affiliates
Mineral exploration		$	365			$	792
Water and wastewater infrastructure			—				327
Total equity in earnings of affiliates		$	365			$	1,119
Income (loss) from continuing operations before income taxes Water and wastewater infrastructure		$	7,983			$	5,526
Mineral exploration			4,985				4,128
Energy			2,057				68
Other			305				10
Unallocated corporate expenses			(4,441	)			(3,418	)
Interest			(2,131	)			(970	)
Total income from continuing operations before income taxes		$	8,758			$	5,344

Revenues for the three months ended April 30, 2006 increased $60,059,000, or 62.1%, to $156,717,000 compared to $96,658,000 for the same period last year. Revenues were up across all divisions with the main increases in the mineral exploration and water and wastewater infrastructure divisions, including the impact of the acquisition of Reynolds, Inc. (“Reynolds”) that closed on September 28, 2005. A further discussion of results of operations by division is presented below.

Gross profit as a percentage of revenues was 25.3% for the three months ended April 30, 2006 compared to 26.5% for the three months ended April 30, 2005. The decrease in gross profit percentage was primarily the result of reduced margins in the water and wastewater infrastructure division arising from a change in product mix with the acquisition of Reynolds. The impact of this product mix shift was partially offset by improved margins in the mineral exploration division due to improved pricing and efficiency and the energy division due to the increased sales of unconventional gas as a result of increased production and pricing.

Selling, general and administrative expenses increased 32.4% to $22,364,000 for the three months ended April 30, 2006 compared to $16,890,000 for the three months ended April 30, 2005. The increase was primarily the result of $3,627,000 in expenses added from the acquisition of Reynolds and from various other categories including an increase in compensation expense of $454,000 associated with stock options under SFAS 123R “Shared-Based Payments,” additional incentive compensation expense of $399,000 from increased profitability in the quarter and wage and benefit increases of $513,000.

Equity in earnings of affiliates decreased $754,000 to $365,000 for the three months ended April 30, 2006 from $1,119,000 in the prior year. The decrease reflects reduced earnings of $427,000 from foreign affiliates in mineral exploration and income in the prior year of $327,000 from a non-recurring domestic joint venture in the water and wastewater infrastructure division.

Depreciation, depletion and amortization increased to $7,066,000 for the three months ended April 30, 2006 compared to $4,013,000 for the same period last year. The increase was primarily the result of depreciation and amortization of $1,922,000 associated with the Reynolds acquisition and increased depletion expense of $707,000 resulting from the increase in production of unconventional gas from the Company’s energy operations.

Interest expense increased to $2,131,000 for the three months ended April 30, 2006 compared to $970,000 for the three months ended April 30, 2005. The increase was primarily a result of increases in the Company’s average borrowings for the period in conjunction with the financing of the Reynolds acquisition.

Income tax expense of $4,116,000 (an effective rate of 47.0%) was recorded for the three months ended April 30, 2006, compared to $2,567,000 (an effective rate of 48.0%) for the same period last year. The improvement in the effective rate is primarily attributable to improved mix of pre-tax earnings, especially in international operations. The effective rate in excess of the statutory federal rate for the periods was 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
		April 30,
		2006				2005
Revenues		$	116,695			$	63,667
Income from continuing operations before income taxes			7,983				5,526

At the beginning of the first quarter the Company established the water and wastewater infrastructure division. The division is a combination of the Company’s legacy water businesses, its geoconstruction division and the Reynolds company.

Water and wastewater infrastructure revenues increased 83.3% to $116,695,000 for the three months ended April 30, 2006 from $63,667,000 for the three months ended April 30, 2005. The increase in revenues was primarily attributable to additional revenues of $46,944,000 from the Company’s acquisition of Reynolds and additional revenues of $2,985,000 from the Company’s continued expansion into water treatment markets.

Income from continuing operations for the water and wastewater infrastructure division increased 44.5% to $7,983,000 for the three months ended April 30, 2006, compared to $5,526,000 for the three months ended April 30, 2005. The increase in income from continuing operations is primarily attributable to income of $2,147,000 from the acquisition of Reynolds and an increase in earnings of the Company’s water treatment initiatives to $1,130,000 from $852,000 in the prior year.

Mineral Exploration Division
(in thousands)

		Three months ended
		April 30,
		2006				2005
Revenues		$	33,628			$	30,559
Income from continuing operations before income taxes			4,985				4,128

Mineral exploration revenues increased 10.0% to $33,628,000 for the three months ended April 30, 2006 from $30,559,000 for the three months ended April 30, 2005. The increase was primarily attributable to continued strength in most of the Company’s markets due to relatively high gold and base metal prices.

Income from continuing operations for the mineral exploration division was up 20.8% to $4,985,000 for the three months ended April 30, 2006, compared to $4,128,000 for the three months ended April 30, 2005. The improved earnings in the division were primarily attributable to the impact of increased exploration activity in most of the Company’s markets partially offset by a decrease of $427,000 in equity earnings of affiliates caused by weather related delays in Latin America and an increase in accrued incentive compensation expense of $286,000 due to higher profitability in the current year.

Energy Division
(in thousands)

		Three months ended
		April 30,
		2006				2005
Revenues		$	5,064			$	1,778
Income from continuing operations before income taxes			2,057				68

Energy revenues increased 184.8% to $5,064,000 for the three months ended April 30, 2006, compared to revenues of $1,778,000 for the three months ended April 30, 2005. The increase in revenues was primarily attributable to increased production from the Company’s unconventional gas properties and higher natural gas prices.

The income from continuing operations for the energy division was $2,057,000 for the three months ended April 30, 2006, compared to income from continuing operations of $68,000 for the three months ended April 30, 2005. The increase in income from continuing operations is due to the increase in production noted above.

Unallocated Corporate Expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $4,441,000 and $3,418,000 for the three months ended April 30, 2006 and 2005, respectively. The increase for the quarter was primarily due to the recognition of compensation expense under SFAS No. 123R (revised December 2004), “Share Based Payments” of $454,000 and an increase in consulting services of $244,000.

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 $100,000,000 of unsecured notes available to be issued before September 15, 2007. At April 30, 2006, the Company has $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 $130,000,000 revolving facility, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit). Amounts outstanding under the Credit Agreement are due and payable September 28, 2010. At April 30, 2006, the Company had $81,200,000 outstanding under the Credit Agreement (see Note 4 of the Notes to Consolidated Financial Statements). The Company was in compliance with its financial covenants at April 30, 2006 and expects to remain in compliance through the foreseeable future.

The Company’s working capital as of April 30, 2006 and April 30, 2005 was $82,481,000 and $69,996,000, respectively. The increase in working capital at April 30, 2006 was primarily attributable to the increase in the balance of accounts receivable as a result of the growth in revenues and working capital acquired in the Reynolds acquisition. 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 for fiscal 2007.

Operating Activities

Cash used in operating activities was $4,257,000 for the three months ended April 30 2006 as compared to $7,277,000 for the three months ended April 30, 2005. The improvement was primarily due to increased earnings offset by an increase in working capital requirements.

Investing Activities

The Company’s capital expenditures, net of disposals, of $14,405,000 for the three months ended April 30, 2006, were directed primarily toward the Company’s expansion into unconventional gas exploration and production. Expenditures related to the Company’s unconventional gas efforts totaled $8,778,000 for the three months ended April 30, 2006, including the construction of gas pipeline infrastructure near the Company’s development projects.

Financing Activities

For the three months ended April 30, 2006, the Company had net borrowings of $12,300,000 under its credit facilities primarily for working capital requirements and to fund capital expenditures. Additionally, proceeds of $198,000 were received from issuance of common stock related to the exercise of stock options.

The Company’s contractual obligations and commercial commitments as of April 30, 2006, 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			$	40,000			$	6,667
Credit agreement			81,200				—				—				81,200				—
Operating leases			15,585				5,584				7,390				1,953				658
Mineral interest obligations			507				103				284				96				24
Total contractual cash obligations			157,292				5,687				21,007				123,249				7,349
Standby letters of credit			6,914				6,914				—				—				—
Asset retirement obligations			534				—				—				—				534
Total contractual obligations and commercial commitments		$	164,740			$	12,601			$	21,007			$	123,249			$	7,883

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 1.00% 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 5 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 – Revenue is recognized on large, long-term contracts 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 and gross profit 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. Revenue is recognized on smaller, short-term contracts using the completed contract method. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined.

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 two 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 evaluating the fair value and future benefits of long-lived assets, including the Company’s gas transportation facilities and equipment, the Company performs an analysis of the anticipated future net cash flows of the related long-lived assets and reduces their carrying value by the excess, if any, of the result of such calculation.

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.

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.

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 12 of the Notes to Consolidated Financial Statements appearing in the Company’s January 31, 2006 Form 10-K and Note 5 of this Form 10-Q. As of April 30, 2006, $60,000,000 of the Company’s long-term debt outstanding carries a fixed-rate and $81,200,000 is variable rate debt. An instantaneous change in interest rates of one percentage point would change the Company’s annual interest expense by $812,000.

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, 2006 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 (see Note 6 of the Notes to Consolidated Financial Statements).

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 April 30, 2006 and 2005. 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 April 30, 2006, the Company held contracts for physical delivery of 4,048,000 million British Thermal Units (“MMBtu”) of natural gas at prices ranging from $8.89 to $9.65 per MMBtu. The estimated fair value of such contracts at April 30, 2006 was $4,025,000. We estimate that a ten percent change in the price of natural gas would have impacted income from continuing operations before taxes by approximately $220,000 for the three months ended April 30, 2006.

ITEM 4. Controls and Procedures

Based on an evaluation of disclosure controls and procedures for the period ended April 30, 2006, 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 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 Principal Financial Officer, for the period ended April 30, 2006, the Company concluded that its internal control over financial reporting is effective as of April 30, 2006. 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 the Reynolds, Inc. business, which was acquired on September 28, 2005, and whose financial statements reflect total assets and revenues constituting 37% and 30%, respectively, of the related consolidated financial statement amounts as of and for the three months ended April 30, 2006. The Company will include Reynolds, Inc. in its evaluation of the design and effectiveness of internal control over financial reporting as of January 31, 2007.

PART II

ITEM 1 — Legal Proceedings

     NONE

ITEM 2 — Changes in Securities

     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 and Reports on Form 8-K

  a) Exhibits

			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.

Reports on Form 8-K

          Form 8-K filed on February 7, 2006 related to the Company’s Board nominations and strategic plan.

          Form 8-K filed on April 4, 2006, related to the Company’s fiscal year ended January 31, 2006 press release.

Form 8-K filed on April 5, 2006 related to the Company’s Settlement Agreement with Steel Partners II, L.P., Steel Partners, L.L.C. and Warren G. Lichtenstein.

* * * * * * * * * *

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.

		Layne Christensen Company
		(Registrant)
DATE: June 7, 2006		/s/ A.B. Schmitt   A.B. Schmitt, President and Chief Executive Officer
DATE: June 7, 2006		/s/ Jerry W. Fanska   Jerry W. Fanska, Sr. Vice President Finance and Treasurer