Edgar Filing: LAYNE CHRISTENSEN CO

FORM 10-Q

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 April 30, 2009


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

For the transition period from to

Commission File Number 001-34195

Layne Christensen Company

(Exact name of registrant as specified in its charter)


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)

(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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company 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 19,451,476 shares of common stock, $.01 par value per share, outstanding on May 29, 2009.

PART I

Item 1. Financial Statements

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


	April 30,			January 31,
	2009			2009
	(unaudited)			(unaudited)

ASSETS

Current assets:
Cash and cash equivalents	$	62,696		$	67,165
Customer receivables, less allowance of $7,278 and $7,878, respectively		106,866			116,234
Costs and estimated earnings in excess of billings on uncompleted contracts		69,932			63,638
Inventories		30,022			31,329
Deferred income taxes		16,737			16,561
Income taxes receivable		7,299			6,806
Restricted deposits-current		775			774
Other		5,044			10,063

Total current assets		299,371			312,570


Property and equipment:
Land		10,774			8,586
Buildings		31,024			27,209
Machinery and equipment		342,082			336,166
Gas transportation facilities and equipment		40,386			39,825
Oil and gas properties		94,524			92,497
Mineral interests in oil and gas properties		21,469			21,248

		540,259			525,531
Less — Accumulated depreciation and depletion		(291,111	)		(278,786	)

Net property and equipment		249,148			246,745


Other assets:
Investment in affiliates		42,182			40,973
Goodwill		90,258			90,029
Other intangible assets, net		20,618			21,002
Restricted deposits-long term		1,156			1,155
Other		7,142			6,883

Total other assets		161,356			160,042


	$	709,875		$	719,357

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,
	2009			2009
	(unaudited)			(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	52,489		$	62,575
Current maturities of long term debt		20,000			20,000
Accrued compensation		23,487			36,252
Accrued insurance expense		9,353			9,173
Other accrued expenses		18,663			17,626
Acquisition escrow obligation-current		824			824
Income taxes payable		1,791			3,254
Billings in excess of costs and estimated earnings on uncompleted contracts		43,315			34,256

Total current liabilities		169,922			183,960


Noncurrent and deferred liabilities:
Long-term debt		26,667			26,667
Accrued insurance expense		10,334			9,947
Deferred income taxes		29,613			29,063
Acquisition escrow obligation-long term		1,156			1,155
Other		12,892			12,468

Total noncurrent and deferred liabilities		80,662			79,300


Common stock, par value $.01 per share, 30,000 shares authorized, 19,399 and 19,383 shares issued and outstanding, respectively		194			194
Capital in excess of par value		339,559			337,528
Retained earnings		129,349			128,353
Accumulated other comprehensive loss		(9,886	)		(10,053	)

Total Layne Christensen Company stockholders’ equity		459,216			456,022

Noncontrolling interest		75			75

Total stockholders’ equity		459,291			456,097


	$	709,875		$	719,357

See Notes to Consolidated Financial Statements.

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


	Three Months
	Ended April 30,
	(unaudited)
	2009			2008

Revenues	$	204,192		$	244,544
Cost of revenues (exclusive of depreciation, depletion and amortization shown below)		(159,904	)		(182,040	)
Selling, general and administrative expenses		(31,700	)		(33,044	)
Depreciation, depletion and amortization		(14,333	)		(12,441	)
Litigation settlement gains		3,161			—
Equity in earnings of affiliates		1,935			2,497
Interest		(810	)		(941	)
Other income (expense), net		(625	)		(46	)


Income before income taxes		1,916			18,529
Income tax expense		(920	)		(7,967	)

Net income attributable to Layne Christensen Company	$	996		$	10,562


Basic income per share	$	0.05		$	0.55


Diluted income per share	$	0.05		$	0.55


Weighted average shares outstanding-basic		19,297			19,091
Dilutive stock options and unvested shares		37			203

Weighted average shares outstanding-diluted		19,334			19,294

See Notes to Consolidated Financial Statements.

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


	Three Months
	Ended April 30,
	(unaudited)
	2009			2008
Cash flow from operating activities:
Net income attributable to Layne Christensen Company	$	996		$	10,562
Adjustments to reconcile net income to cash from operations:
Depreciation, depletion and amortization		14,333			12,441
Deferred income taxes		379			621
Share-based compensation		1,957			1,086
Share-based compensation excess tax benefits		(42	)		(58	)
Equity in earnings of affiliates		(1,935	)		(2,497	)
Dividends received from affiliates		726			278
(Gain) loss from disposal of property and equipment		(46	)		236
Changes in current assets and liabilities, net of effects of acquisitions:
(Increase) decrease in customer receivables		10,099			(8,548	)
Increase in costs and estimated earnings in excess of billings on uncompleted contracts		(6,232	)		(12,636	)
(Increase) decrease in inventories		811			(3,114	)
Decrease in other current assets		4,803			557
Decrease in accounts payable and accrued expenses		(22,610	)		(3,146	)
Increase in billings in excess of costs and estimated earnings on uncompleted contracts		9,059			1,708
Other, net		(3,159	)		(1,500	)

Cash provided by (used in) operating activities		9,139			(4,010	)

Cash flow from investing activities:
Additions to property and equipment		(9,939	)		(9,082	)
Additions to gas transportation facilities and equipment		(561	)		(1,613	)
Additions to oil and gas properties		(2,027	)		(3,637	)
Additions to mineral interests in oil and gas properties		(221	)		(1,578	)
Payment of cash purchase price adjustment on prior year acquisition		(229	)		—
Proceeds from disposal of property and equipment		146			426
Deposit of cash into restricted accounts		—			(680	)

Cash used in investing activities		(12,831	)		(16,164	)

Cash flow from financing activities:
Issuance of common stock upon exercise of stock options		32			339
Excess tax benefit on exercise of share-based instruments		42			58

Cash provided by financing activities		74			397

Effects of exchange rate changes on cash		(851	)		(124	)

Net decrease in cash and cash equivalents		(4,469	)		(19,901	)
Cash and cash equivalents at beginning of period		67,165			73,068

Cash and cash equivalents at end of period	$	62,696		$	53,167

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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, 2009, 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. Separate full-cost pools are established for each country in which the Company has exploration activities. Depletion expense was $3,661,000 and $2,793,000 for the three months ended April 30, 2009 and 2008, respectively.

our fiscal 2010, application of the ceiling test requires pricing future revenues at the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of reporting period, unless prices are defined by contractual arrangements such as the Company’s fixed-price physical delivery forward sales contracts. Application of the ceiling test 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 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 — 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 and reducing 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 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. The Company’s cash equivalents included $10,000,000 of short term commercial paper as of April 30, 2009 (none was held as of January 31, 2009). 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.

Restricted Deposits — Included in restricted deposits are escrow funds associated with various acquisitions as described in Note 2, of the Notes to Consolidated Financial Statements.

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. In general, the Company records income tax expense during interim periods based on its best estimate of the full year’s effective tax rate. However, income tax expense relating to adjustments to the Company’s liabilities for FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement 109” (“FIN48”), is accounted for discretely in the interim period in which it occurs.

As of April 30 and January 31, 2009, the total amount of unrecognized tax benefits recorded under FIN 48 was $7,974,000 and $7,612,000, 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. The Company classifies uncertain tax positions as non-current income tax liabilities unless expected to be paid in one year. The Company reports income tax-related interest and penalties as a component of income tax expense. As of April 30 and January 31, 2009, the total amount of accrued income tax-related interest and penalties included in the balance sheet was $3,122,000 and $2,872,000, respectively.

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 (“EPS”) are based upon the weighted average number of common and dilutive equivalent shares outstanding. Options to purchase common stock and unvested restricted shares 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), “Share-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 April 30, 2009, the Company had unrecognized compensation expense of $5,953,000 to be recognized over a weighted average period of 1.87 years. The Company determines the fair value of stock-based compensation granted in the form of stock options using the Black-Scholes model.

Supplemental Cash Flow Information — The amounts paid for income taxes and interest are as follows (in thousands):


	Three Months
	Ended April 30,
	2009		2008
Income taxes	$	1,359	$	1,171
Interest		1,175		943

The Company had earnings on restricted deposits of $1,000 and $10,000 for the three months ended April 30, 2009 and 2008, respectively, which were treated as non-cash items as the earnings were restricted for the account of the escrow beneficiaries. Also for the three months ended April 30, 2009, the Company received land and buildings valued at $2,828,000 in a non-cash settlement of a legal dispute in Australia.

During fiscal year 2009, the Company entered into financing obligations for software licenses amounting to $1,298,000, payable over three years. The associated assets are recorded as Other Intangible Assets in the balance sheet.

New Accounting Pronouncements — In February 2008, the Financial Accounting Standards Board (“the FASB”) issued Staff Position 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”), which delayed the effective date of SFAS 157, “Fair Value Measurements”(“SFAS 157”), for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. These nonfinancial items include assets and liabilities such as reporting units measured at fair value in a goodwill impairment test and nonfinancial assets acquired and liabilities assumed in a business combination. On February 1, 2009, the Company adopted SFAS 157 for those nonfinancial assets within the scope of FSP 157-2. Adoption of SFAS 157 for those nonfinancial assets did not have a material impact on the Company’s financial position, results of operations or liquidity.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. SFAS 141R also establishes disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. The Company adopted this standard as of February 1, 2009. The adoption of SFAS 141R did not have a significant effect on the Company’s financial position, results of operations or liquidity.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”). SFAS 160 requires us to classify noncontrolling interests (previously referred to as “minority interest”) as part of consolidated net earnings and to include the accumulated amount of noncontrolling interests, previously classified as minority interest outside of equity, as part of stockholders’ equity. Since there was no income attributable to noncontrolling interests during the periods presented herein, net income and earnings per share continue to reflect amounts attributable only to the Company. In our presentation of stockholders’ equity we distinguish between equity amounts attributable to Layne Christensen Company stockholders and amounts attributable to the noncontrolling interests. In addition to these financial reporting changes, SFAS 160 provides for significant changes in accounting related to noncontrolling interests; specifically, increases and decreases in our controlling financial interests in consolidated subsidiaries will be reported in equity similar to treasury stock transactions. If a change in ownership of a consolidated subsidiary results in loss of control and deconsolidation, any retained ownership interests are remeasured with the gain or loss reported in net earnings. The Company adopted this standard, which is applied retrospectively, as of February 1, 2009, and reclassified minority interest in the amounts of $75,000 as of February 1, 2009 and $398,000 as of February 1, 2008, as a component of stockholders’ equity.

In March 2008, the FASB issued SFAS No.161, “Disclosures about Derivative Instruments and Hedging Activities an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The Company adopted this standard as of February 1, 2009. The adoption of SFAS 161 did not have a material impact on the Company’s financial position, results of operations or liquidity.

In June 2008, the FASB issued Staff Position EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” (“FSP EITF 03-6-1”). Under this FSP, unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securities and should be included in the computation of earnings per share pursuant to the two-class method. The Company adopted FSP EITF 03-6-1 as of February 1, 2009, and has concluded that it has no such participating

securities to consider for purposes of its shares outstanding and EPS calculations, and the treasury stock method will continue to be used, as described in Note 1 of the Notes to Consolidated Financial Statements.

In April 2009, the FASB issued FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which provides additional guidance in accordance with SFAS No. 157. If an entity determines that either the volume or level of activity for an asset or liability has significantly decreased from normal conditions, or that price quotations or observable inputs are not associated with orderly transactions, increased analysis and management judgment will be required to estimate fair value. The objective in fair value measurement remains unchanged from what is prescribed in SFAS No. 157 and should be reflective of the current exit price. Disclosures in interim and annual periods must include inputs and valuation techniques used to measure fair value, along with any changes in valuation techniques and related inputs during the period. In addition, disclosures for debt and equity securities must be provided on a more disaggregated basis than what was required in SFAS No. 157. FSP No. FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009. The Company does not expect FSP No. FAS 157-4 to have a material impact on its financial position, results of operations or cash flows.

In April 2009, the FASB issued FSP No. FAS 107-1 and Accounting Principles Bulletin (APB) No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” to require disclosures about fair value of financial instruments for publicly traded companies for both interim and annual periods. Historically, these disclosures were only required annually. The interim disclosures are intended to provide financial statement users with more timely and transparent information about the effects of current market conditions on an entity’s financial instruments that are not otherwise reported at fair value. FSP No. FAS 107-1 is effective for interim reporting periods ending after June 15, 2009. Comparative disclosures are only required for periods ending after the initial adoption. The Company does not expect FSP No. FAS 107-1 to have a material impact on its financial position, results of operations or cash flows.

2. Acquisitions

Fiscal Year 2009

The Company completed three acquisitions during the fiscal 2009 year as described below:

•		On October 24, 2008, the Company acquired 100% of the stock of Meadors Construction Co., Inc. (“Meadors”), a construction company operating primarily in Florida. The operation will be combined with similar service lines and will serve to foster our further expansion into Florida and the southeast.

•		On August 7, 2008, the Company acquired certain assets and liabilities of Moore & Tabor, a geotechnical construction firm operating in California.

•		On May 5, 2008, the Company acquired certain assets and liabilities of Wittman Hydro Planning Associates (“WHPA”), a water consulting firm specializing in hydrologic systems modeling and analysis.

		The aggregate purchase price of $8,926,000, comprised of cash of $8,815,000 ($1,150,000 of which was placed in escrow to secure certain representations, warranties and idemnifications under the purchase agreements) and expenses of $111,000, was as follows:


(in thousands)
	Meadors		Moore & Tabor		WHPA		Total

Cash	$	4,536	$	1,785	$	2,494	$	8,815
Expenses		53		33		25		111

Total purchase price	$	4,589	$	1,818	$	2,519	$	8,926

Escrow deposits	$	700	$	150	$	300	$	1,150

The purchase price for each acquisition has been allocated based on the fair value of the assets and liabilities acquired, determined based on the Company’s internal operational assessments and other analyses. Based on the Company’s allocations of the purchase price, the acquisitions had the following effect on the Company’s consolidated financial position as of their respective closing dates:


(in thousands)
	Meadors		Moore & Tabor		WHPA		Total

Working capital	$	2,072	$	427	$	394	$	2,893
Property and equipment		592		798		40		1,430
Goodwill		1,865		593		1,832		4,290
Other intangible assets		60		—		250		310
Other assets		—		—		3		3

Total purchase price	$	4,589	$	1,818	$	2,519	$	8,926

The identifiable intangible assets associated with Meadors consist of non-compete agreements valued at $60,000 and have a weighted-average useful life of two years. The identifiable intangible assets associated with WHPA consist of patents valued at $250,000, and have a weighted-average life of 15 years. The $4,290,000 of aggregate goodwill was assigned to the water infrastructure segment and is expected to be deductible for tax purposes.

The results of operations of the acquired entities have been included in the Company’s consolidated statements of income commencing with the respective closing dates. Pro forma amounts for prior periods have not been presented as the acquisitions would not have had a significant effect on the Company’s consolidated revenues or net income.

In addition to the initial purchase price, there is contingent consideration up to a maximum of $2,500,000 (the “WHPA Earnout Amount”), which is based on a percentage of the amount by which WHPA’s earnings before interest, taxes, depreciation and amortization exceed a threshold amount during the 36 months following the acquisition. If earned, up to 80% of the WHPA Earnout Amount may be paid with Layne common stock, at the Company’s discretion. Any portion of the WHPA Earnout Amount which is ultimately paid will be accounted for as additional purchase consideration.

Fiscal Year 2008

The Company completed two acquisitions during the fiscal 2008 year as described below:

•		On December 31, 2007 (the “Tierdael Closing Date”), the Company acquired certain assets and liabilities of Tierdael Construction (“Tierdael”), a pipeline and utility construction contractor in Denver which was combined with similar service lines.

•		On November 30, 2007 (the “SolmeteX Closing Date”), the Company acquired certain assets and liabilities of SolmeteX, Inc. (“SolmeteX”), a water and wastewater research and development business and a supplier of wastewater filtration products to the dental market.

The aggregate purchase price of $20,696,000, comprised of cash of $20,146,000 ($1,665,000 of which was placed in escrow to secure certain representations, warranties and idemnifications under the purchase agreements), assumed liabilites of $226,000 and expenses of $324,000, was as follows:


(in thousands)
	Tierdael		Solmetex		Total

Cash	$	6,646	$	13,500	$	20,146
Assumed liabilities		226		—		226
Expenses		238		86		324

Total purchase price	$	7,110	$	13,586	$	20,696

Escrow deposits	$	665	$	1,000	$	1,665

In addition to the initial purchase price, there is contingent consideration up to a maximum of $1,000,000 (the “SolmeteX Earnout Amount”), which is based on a percentage of the amount of SolmeteX’s revenues during the 36 months following the acquisition. Any portion of the SolmeteX Earnout Amount that is ultimately paid will be accounted for as additional purchase consideration. Through April 30, 2009, the contingent earnout consideration earned by SolmeteX was $262,000, of which $33,000 was paid in March 2008 and $229,000 was paid in April 2009.


(in thousands)
	Tierdael		Solmetex		Total

Working capital	$	3,983	$	64	$	4,047
Property and equipment		3,127		115		3,242
Goodwill		—		7,270		7,270
Tradenames		—		2,962		2,962
Patents		—		2,543		2,543
Deferred income taxes		—		551		551
Other intangible assets		—		81		81

Total purchase price	$	7,110	$	13,586	$	20,696

Escrow deposits	$	665	$	1,000	$	1,665

Of the $6,056,000 of identifiable intangible assets associated with Solmetex, $21,000 was assigned to research and development assets that were written off in selling, general and administrative expenses at the date of acquisition in accordance with FASB Interpretation No. 4, “Applicability of FASB Statement No. 2 to Business Combinations Accounted for by the Purchase Method.” The remaining $6,035,000 of acquired intangible assets have a weighted-average useful life of approximately 15.4 years, comprised of tradenames (15-year weighted-average useful life), patents (15-year weighted-average useful life), and other assets (20-year average useful life). The $7,270,000 goodwill was assigned to the water infrastructure segment. Of that total amount, $7,053,000 is expected to be deductible for tax purposes.

3. Goodwill and Other Intangible Assets

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


	April 30, 2009							January 31, 2009
						Weighted							Weighted
						Average							Average
	Gross					Amortization		Gross					Amortization
	Carrying		Accumulated			Period in		Carrying		Accumulated			Period in
	Amount		Amortization			years		Amount		Amortization			years
Goodwill	$	90,258	$	—				$	90,029	$	—

Amortizable intangible assets:
Tradenames	$	18,962	$	(2,478	)		29	$	18,962	$	(2,275	)		29
Customer-related		332		(332	)		2		332		(332	)		2
Patents		3,152		(616	)		14		3,152		(569	)		14
Non-competition agreements		439		(394	)		5		439		(387	)		5
Other		2,590		(1,037	)		12		2,590		(910	)		12

Total amortizable intangible assets	$	25,475	$	(4,857	)			$	25,475	$	(4,473	)

Amortizable intangible assets are being amortized over their estimated useful lives of two to 40 years with a weighted average amortization period of 25 years. Total amortization expense for other intangible assets was $384,000 and $303,000 for the three months ended April 30, 2009 and 2008, respectively.

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


			Water
	Energy		Infrastructure		Total
Balance February 1, 2009	$	950	$	89,079	$	90,029
Additions		—		229		229

Balance, April 30, 2009	$	950	$	89,308	$	90,258

4. Indebtedness

The Company maintains an agreement (“Master Shelf Agreement”) whereby it can issue up to $105,000,000 in unsecured notes before September 15, 2009. On July 31, 2003, 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 that began on July 31, 2008. 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.

The Company also maintains a revolving credit facility under an Amended and Restated Loan Agreement (the “Credit Agreement”) with Bank of America, N.A., as Administrative Agent and as Lender (the “Administrative Agent”), and the other Lenders listed therein (the “Lenders”), which contains a revolving loan commitment of $200,000,000, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit).

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 April 30, 2009, there were letters of credit of $15,499,000 and no borrowings outstanding on the Credit Agreement resulting in available capacity of $184,501,000.

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, leverage and minimum tangible net worth. The Company was in compliance with its covenants as of April 30, 2009.

Debt outstanding as of April 30, 2009, and January 31, 2009, was as follows (in thousands):


	April 30,			January 31,
	2009			2009
Long-term debt:
Credit Agreement	$	—		$	—
Senior Notes		46,667			46,667

Total debt		46,667			46,667

Less current maturities		(20,000	)		(20,000	)

Total long-term debt	$	26,667		$	26,667

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 April 30, 2009, the Company had committed to deliver 5,025,000 million British Thermal Units (“MMBtu”) of natural gas through March 2010 at prices ranging from $7.63 to $10.69 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, 2009, was $25,003,000.

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. As of April 30, 2009, the Company held option contracts with an aggregate U.S. dollar notional value of $7,500,000 which are intended to hedge exposure to Australian dollar fluctuations over a period to January 31, 2010. As of April 30, 2009 and January 31, 2009, the fair value of outstanding derivatives was $351,000 and $158,000, respectively, recorded in other accrued expenses on the consolidated balance sheet. The Company does not enter into foreign currency derivative financial instruments for speculative or trading purposes.

6.Other Comprehensive Income

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


	Three Months Ended
	April 30,
	2009			2008
Net income	$	996		$	10,562
Other comprehensive income, net of taxes:
Foreign currency translation adjustments		285			461
Change in unrealized loss of foreign exchange contracts		(118	)		—

Comprehensive income	$	1,163		$	11,023

The components of accumulated other comprehensive loss for the three months ended April 30, 2009 and 2008 are as follows (in thousands):


							Unrealized			Accumulated
	Cumulative			Unrecognized			Loss on			Other
	Translation			Pension			Exchange			Comprehensive
	Adjustment			Liability			Contracts			Loss
Balance, February 1, 2009	$	(8,940	)	$	(1,017	)	$	(96	)	$	(10,053	)
Period change		285			—			(118	)		167

Balance, April 30, 2009	$	(8,655	)	$	(1,017	)	$	(214	)	$	(9,886	)


							Unrealized		Accumulated
	Cumulative			Unrecognized			Loss on		Other
	Translation			Pension			Exchange		Comprehensive
	Adjustment			Liability			Contracts		Loss
Balance, February 1, 2008	$	(6,391	)	$	(596	)	$	—	$	(6,987	)
Period change		461			—			—		461

Balance, April 30, 2008	$	(5,930	)	$	(596	)	$	—	$	(6,526	)

7. Litigation Settlement Gains

In fiscal 2000, the Company initiated litigation against a former owner of a subsidiary and associated partners. The action stemmed from alleged competition in violation of non-competition agreements, and sought damages for lost profits and recovery of legal expenses. During the three months ended April 30, 2009, the Company entered into an agreement whereby it received certain land and buildings in settlement of these claims. The settlement was valued at $2,828,000, based on management’s estimate of the fair market value of the land and buildings received considering current market conditions and information provided by a third party appraisal.

In fiscal 2008, the Company initiated litigation against former officers of a subsidiary and associated energy production companies. During September 2008, the Company entered into a settlement agreement whereby it will receive certain payments over a period through September 2009. Payments were received during the three months ended April 30, 2009, of $333,000, net of contingent attorney fees.

8. Other Income (Expense)

Other income (expense) consisted of the following for the three months ended April 30, 2009 and 2008 (in thousands):


	Three Months Ended
	April 30,
	2009			2008
Gain (loss) from disposal of property and equipment	$	46		$	(236	)
Interest income		56			454
Currency exchange gain (loss)		(505	)		80
Other		(222	)		(344	)

Total	$	(625	)	$	(46	)

9. 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. Depending on market conditions, the Company expects to use assets of the plan to settle its benefit obligations during 2010. Assets of the plan consist primarily of bonds and government securities.

Net periodic pension cost for the three months ended April 30, 2009 and 2008 includes the following components (in thousands):


	Three Months Ended April 30,
	2009			2008
Service cost	$	22		$	24
Interest cost		119			113
Expected return on assets		(67	)		(134	)
Net amortization		26			54

Net periodic pension cost	$	100		$	57

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, 2009 and 2008 include the following components (in thousands):


	Three Months
	Ended April 30,
	2009		2008
Service cost	$	73	$	44
Interest cost		44		26

Net periodic pension cost	$	117	$	70

10. Fair Value Measurements

In September 2006, the FASB issued SFAS 157, “Fair Value Measurements,” which defines fair value, establishes a three-level fair value hierarchy based upon the assumptions (inputs) used to price assets or liabilities, and expands disclosures about fair value measurements. The hierarchy requires the Company to maximize the use of observable inputs and minimize the use of unobservable inputs. The three levels of inputs used to measure fair value are listed below:

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 — Observable inputs other than those included in Level 1, such as quoted market prices for similar assets and liabilities in active markets or quoted prices for identical assets in inactive markets.

Level 3 — Unobservable inputs reflecting our own assumptions and best estimate of what inputs market participants would use in pricing an asset or liability.

The Company’s assessment of the significance of a particular input to the fair value in its entirety requires judgment and considers factors specific to the asset or liability. The Company’s financial instruments held at fair value, which include short term cash equivalents, restrictive deposits held in acquisition escrow accounts, and foreign exchange forward contracts, are presented below for the periods ended April 30, 2009 and January 31, 2009 (in thousands):


				Fair Value Measurements
	Carrying Value			Level 1		Level 2			Level 3
April 30, 2009
Financial Assets:
Cash equivalents held at fair value	$	20,065		$	20,065	$	—		$	—

Restricted deposits held at fair value		1,931			1,931		—			—

Total	$	21,996		$	21,996	$	—		$	—


Financial Liabilities:
Forward Currency Contracts	$	(351	)	$	—	$	(351	)	$	—


January 31, 2009
Financial Assets:
Restricted deposits held at fair value	$	1,929		$	1,929	$	—		$	—


Financial Liabilities:
Forward Currency Contracts	$	(158	)	$	—	$	(158	)	$	—

The Company had no Level 3 fair value measurements during the first quarter of fiscal 2010, or for the year ended January 31, 2009.

11. Stock and Stock Option Plans

In October 2008, the Company amended the Rights Agreement signed October 1998 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 20% 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 $75.00. The Company is entitled to redeem the Right at $0.01 per Right at any time before a person has acquired 20% or more of the Company’s outstanding common stock. The Rights expire three 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 at a price fixed by the Board of Directors or a committee. As of April 30, 2009, there were an aggregate of 1,450,000 shares registered under the plans, 252,000 of which remain available to be granted under the plans. Of this amount, 250,000 shares may only be granted as stock in payment of bonuses, and 2,000 may be issued as stock or options. 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 three months ended April 30, 2009, the Company granted approximately 9,000 restricted shares which generally ratably vest over periods of one to four years from the grant date.

The Company recognized $1,957,000 and $1,086,000 of compensation cost for these share-based plans during the three months ended April 30, 2009 and 2008, respectively. Of these amounts, $376,000 and $342,000, respectively, related to nonvested stock. The total income tax benefit recognized for share-based compensation arrangements was $763,000 and $420,000 for the three months ended April 30, 2009 and 2008, respectively.

A summary of nonvested share activity for the three months ended April 30, 2009, is as follows:


			Weighted		Aggregate
			Average		Intrinsic
	Number of		Grant Date		Value (in
	Shares		Fair Value		thousands)

Nonvested stock at January 31, 2009		89,809	$	40.48

Granted		8,636		15.78
Vested		—

Nonvested stock at April 30, 2009		98,445	$	38.31	$	2,132

Significant option groups outstanding at April 30, 2009, related exercise price and remaining contractual term follows:


							Remaining
							Contractual
Grant	Options		Options		Exercise		Term
Date	Outstanding		Exercisable		Price		(Months)

2/00		1,900		1,900	$	5.500		10
4/00		13,794		13,794		3.495		12
6/04		20,000		20,000		16.600		62
6/04		77,376		77,376		16.650		62
6/05		10,000		10,000		17.540		74
9/05		157,000		94,500		23.050		77
1/06		191,481		138,923		27.870		81
6/06		10,000		10,000		29.290		86
6/06		70,000		35,000		29.290		86
6/07		65,625		13,125		42.260		98
7/07		33,000		8,250		42.760		99
9/07		3,000		750		55.480		101
2/08		74,524		24,835		35.710		105
1/09		6,000		6,000		24.10		116
2/09		201,311		—		15.78		117
2/09		4,580		4,580		15.78		117

		939,591		459,033

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 weighted average fair value at the date of grant for the options granted was $8.50 and $16.54 for the three months ended April 30, 2009 and 2008, respectively. The options have terms of ten years from the date of grant and generally vest ratably over periods of one month to five years. Transactions for stock options for the three months ended April 30, 2009, were as follows:


	Stock Options
						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, 2009		741,441		$	27.435		6.99	$	279
Granted		205,891			15.780				—
Exercised		(7,741	)		4.125				129
Canceled		—			—				—
Forfeited		—			—				—
Expired		—			—				—
Outstanding at April 30, 2009		939,591			25.073		7.44		2,022

Shares Exercisable		459,033		$	24.562		6.40	$	838

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.

12. 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 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 also include the design and construction of water and wastewater treatment facilities, 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, Ranney collector wells, sewer rehabilitation and water and wastewater transmission lines. The division also offers environmental services to assess and monitor groundwater contaminants.

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, primarily 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 are presented below. 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
	April 30,
	2009			2008

Revenues
Water infrastructure	$	168,087		$	180,572
Mineral exploration		24,794			51,094
Energy		10,321			11,879
Other		990			999

Total revenues	$	204,192		$	244,544


Equity in earnings of affiliates
Mineral exploration	$	1,935		$	2,497


Income before income taxes
Water infrastructure	$	4,527		$	9,189
Mineral exploration		1,767			11,636
Energy		2,588			4,476
Other		148			20
Unallocated corporate expenses		(6,304	)		(5,851	)
Interest		(810	)		(941	)


Total income before income taxes	$	1,916		$	18,529


Geographic Information:
Revenues
United States	$	182,406		$	200,440
Africa/Australia		10,375			26,674
Mexico		5,008			10,800
Other foreign		6,403			6,630

Total revenues	$	204,192		$	244,544

13. 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, bundled 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.

On April 30, 2008, Levelland/Hockley County Ethanol, LLC (“Levelland”) filed a Complaint against the Company in the District Court for Hockley County, Texas. On May 28, 2008, the Company removed the case to the United States District Court for the Northern District of Texas, Lubbock Division. On June 2, 2008, Levelland filed a First Amended Complaint against the Company in the Federal District Court for the Northern District of Texas, Lubbock Division. Levelland owns an ethanol plant located in Levelland, Texas. In July 2007, Levelland entered into a lease agreement with the Company for certain water treatment equipment for the ethanol plant. Levelland alleges that the equipment leased from the Company fails to treat the water coming into the ethanol plant to required levels. The First Amended Complaint seeks damages for breach of contract, breach of warranty, violation of the Texas Deceptive Trade Practices Act, negligence, negligent misrepresentation and fraud, in connection with the design and construction of the water treatment facility. The Company believes that it has meritorious defenses to the claims, intends to vigorously defend against them and does not believe that the claims will have a significant effect on its business, 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, 2009.

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 availability of credit, 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
	2009			2008			Three Months
Revenues:
Water infrastructure		82.3	%		73.8	%		(6.9	)%
Mineral exploration		12.1			20.9			(51.5	)
Energy		5.1			4.9			(13.1	)
Other		0.5			0.4			(0.9	)

Total net revenues		100.0	%		100.0	%		(16.5	)

Cost of revenues		(78.3	)%		(74.4	)%		(12.2	)
Selling, general and administrative expenses		(15.5	)		(13.5	)		(4.1	)
Depreciation, depletion and amortization		(7.0	)		(5.1	)		15.2
Litigation settlement gains		1.5			—			*
Equity in earnings of affiliates		0.9			1.0			(22.5	)
Interest		(0.4	)		(0.4	)		(13.9	)
Other, net		(0.3	)		—			*

Income before income taxes		0.9			7.6			(89.7	)
Income tax expense		(0.4	)		(3.3	)		(88.5	)

Net income		0.5	%		4.3	%		(90.6	)


*		not meaningful

Revenues, equity in earnings of affiliates and income before income taxes pertaining to the Company’s operating segments are presented below. 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
	April 30,
	2009			2008
Revenues
Water infrastructure	$	168,087		$	180,572
Mineral exploration		24,794			51,094
Energy		10,321			11,879
Other		990			999

Total revenues	$	204,192		$	244,544

Equity in earnings of affiliates
Mineral exploration	$	1,935		$	2,497

Income before income taxes
Water infrastructure	$	4,527		$	9,189
Mineral exploration		1,767			11,636
Energy		2,588			4,476
Other		148			20
Unallocated corporate expenses		(6,304	)		(5,851	)
Interest		(810	)		(941	)

Total income before income taxes	$	1,916		$	18,529

Revenues for the three months ended April 30, 2009, decreased $40,352,000, or 16.5%, to $204,192,000 compared to $244,544,000 for the same period last year. A further discussion of results of operations by division is presented below.

Cost of revenues decreased $22,136,000 to $159,904,000, or 78.3% of revenues, for the three months ended April 30, 2009, compared to $182,040,000, or 74.4% of revenues, for the same period last year. The increase as a percentage of revenues was primarily focused in the water infrastructure division as the result of a shift in revenue mix to a higher concentration of heavy construction, which typically carries a lower margin, difficulties on several projects and pricing pressures from increased competition. Also contributing was reduced volume and pricing in the mineral exploration division.

Selling, general and administrative expenses decreased 4.1% to $31,700,000 for the three months ended April 30, 2009, compared to $33,044,000 for the same period last year. The decrease was primarily the result of a combination of decreased compensation related expenses of $3,062,000 offset by increased operating tax expense of $1,906,000. Compensation expenses declined based on lower accruals for incentive compensation given the Company’s reduced earnings, as well as headcount reductions. The increased operating tax expense is primarily due to a reassessment of the recoverability of value added tax balances in certain foreign jurisdictions given recent declines in those economies and accruals for certain other operating tax expenses.

Depreciation, depletion and amortization increased 15.2% to $14,333,000 for the three months ended April 30, 2009, compared to $12,441,000 for the same period last year. The increase was primarily due to higher depletion in the energy division as a result of reduced estimated lives of proven oil and gas reserves, driven by lower natural gas prices.

During the three months ended April 30, 2009, the Company received litigation settlements valued at $3,161,000. The settlements included receipt of land and buildings valued at $2,828,000, and cash receipts of $333,000, net of contingent attorney fees.

Equity in earnings of affiliates decreased 22.5% to $1,935,000 for the three months ended April 30, 2009, from $2,497,000 for the same period last year. The decrease reflects the impact of softening exploration demand for gold and copper in South America. We expect our equity in earnings of affiliates to remain positive, but reduced from prior year levels through the balance of the fiscal year.

Interest expense decreased to $810,000 for the three months ended April 30, 2009, compared to $941,000 for the same period last year. The decrease was a result of scheduled debt reductions and reduced borrowing needs for working capital.

Income tax expense of $920,000 (an effective rate of 48.0%) was recorded for the three months ended April 30, 2009, compared to $7,967,000 (an effective rate of 43.0%) for the same period last year. The increase in the effective rate is primarily attributable to the impact of nondeductible expenses as pretax income declines. 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 Infrastructure Division
(in thousands)


	Three Months Ended
	April 30,
	2009		2008
Revenues	$	168,087	$	180,572
Income before income taxes		4,527		9,189

Water infrastructure revenues decreased 6.9% to $168,087,000 for the three months ended April 30, 2009, from $180,572,000 for the same period last year. The decrease occurred across all major product lines, except pipeline and larger water treatment plant construction which was aided by previously announced acquisitions. The most affected locations were in the Western U.S. where a decrease in housing construction and the economic effects of budget constraints on municipal government spending has significantly impacted our markets. Bidding activity, particularly in the heavy construction markets, remains relatively strong albeit with more competitors.

Income before income taxes for the water infrastructure division decreased 50.7% to $4,527,000 for the three months ended April 30, 2009, compared to $9,189,000 for the same period last year. Reduced revenue levels and margin pressures from increased competition, as well as difficulties on several projects contributed to the decline. Also contributing factors were worse than expected workers’ compensation and healthcare insurance experience. Cost control measures including headcount reductions continue as we seek to match expenses to lower activity levels in most of our product lines.

The backlog in the water infrastructure division was $481,615,000 as of April 30, 2009, compared to $427,863,000 as of January 31, 2009, and $370,742,000 as of April 30, 2008.

Mineral Exploration Division
(in thousands)


	Three Months Ended
	April 30,
	2009		2008
Revenues	$	24,794	$	51,094
Income before income taxes		1,767		11,636

Mineral exploration revenues decreased 51.5% to $24,794,000 for the three months ended April 30, 2009, from $51,094,000 for the same period last year. The decreased activity levels which began in the fourth quarter of last year continued, with revenue declines in virtually all of the division’s markets driven by tightening credit and economic uncertainty. We anticipate declines against last year’s levels for the balance of the fiscal year.

Income before income taxes for the mineral exploration division was down 84.8% to $1,767,000 for the three months ended April 30, 2009, compared to $11,636,000 for the same period last year. During the period, we had two unusual items, receipt of a litigation settlement in Australia of $2,828,000 and increased operating tax expense of $1,906,000 due to a reassessment of the recoverability of value added taxes in certain foreign jurisdictions and accruals for certain other operating tax expenses. Excluding these two items, income before income taxes would have decreased by 92.7% to $845,000. The equity in earnings of affiliates declined at a slower rate than the remainder of the division, reflecting higher stability from certain longer term contracts. Operations in North America were profitable, offset by losses in Africa and Australia. We have and continue to aggressively reduce staffing levels and other costs in dealing with the reduced market activity.

Energy Division
(in thousands)


	Three Months Ended
	April 30,
	2009		2008
Revenues	$	10,321	$	11,879
Income before income taxes		2,588		4,476

Energy revenues decreased 13.1% to $10,321,000 for the three months ended April 30, 2009, compared to revenues of $11,879,000 for the same period last year. The decrease in revenues was attributable to lower gas prices in the Company’s market for the portion of the Company’s production which was not forward sold. We anticipate holding production for the near term to levels which have been forward sold.

Income before income taxes for the energy division decreased 42.2% to $2,588,000 for the three months ended April 30, 2009, compared to $4,476,000 for the same period last year. The decrease in income before income taxes is due to the impact on revenues from lower gas prices as noted above, as well as higher depletion based on decreased proved oil and gas reserves.

A ceiling test impairment was recorded in the fourth quarter of fiscal 2009. While no further impairment was required in the first quarter of fiscal 2010, should gas pricing remain low and Layne Energy is not able to replace current forward sales contracts at attractive prices, additional impairments could occur during the course of the year.

Unallocated Corporate Expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $6,304,000 for the three months ended April 30, 2009, compared to $5,851,000 for the same period last year. The increase for the quarter was primarily due to reduced interest earnings on available cash balances and increased share-based compensation.

Liquidity and Capital Resources

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’s primary sources of liquidity have historically been cash from operations, supplemented by borrowings under its credit facilities.

The Company maintains an agreement (the “Master Shelf Agreement”) under which it may issue unsecured notes and an unsecured $200,000,000 revolving credit facility (the “Credit Agreement”) which extends to November 15, 2011. Under the Master Shelf Agreement, the Company has an additional $45,000,000 of unsecured notes available to be issued before September 15, 2009. At April 30, 2009, the Company has $46,667,000 in notes outstanding under the Master Shelf Agreement. At April 30, 2009, the Company had letters of credits of $15,499,000 and no borrowings outstanding under the Credit Agreement resulting in available capacity of $184,501,000.

The Company’s Master Shelf Agreement and Credit Agreement each contain certain covenants including restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions, transfer or sale of assets, transactions with affiliates and payment of dividends. These provisions generally allow such activity to occur, subject to specific limitations and continued compliance with financial maintenance covenants. Significant financial maintenance covenants are fixed charge coverage ratio, maximum leverage ratio and minimum tangible net worth. Covenant levels and definitions are consistent between the two agreements. The Company was in compliance with its covenants as of April 30, 2009, and expects to be in compliance in fiscal 2010.

Compliance with the financial covenants is required on a quarterly basis, using the most recent four fiscal quarters. The Company’s fixed charge coverage ratio and leverage ratio covenants are based on ratios utilizing adjusted EBITDA and adjusted EBITDAR, as defined in the agreements. Adjusted EBITDA is generally defined as consolidated net income excluding net interest expense, provision for income taxes, gains or losses from extraordinary items, gains or losses from the sale of capital assets, non-cash items including depreciation and amortization, and share-based compensation. Equity in earnings of affiliates is included only to the extent of dividends or distributions received. Adjusted EBITDAR is defined as adjusted EBITDA, plus rent expense. The Company’s tangible net worth covenant is based on stockholders’ equity less intangible assets. All of these measures are considered non-GAAP financial measures and are not intended to be in accordance with accounting principles generally accepted in the United States.

The Company’s minimum fixed charge coverage ratio covenant is the ratio of adjusted EBITDAR to the sum of fixed charges. Fixed charges consist of rent expense, interest expense, and principal payments of long-term debt. The Company’s leverage ratio covenant is the ratio of total funded indebtedness to adjusted EBITDA. Total funded indebtedness generally consists of outstanding debt, capital leases, unfunded pension liabilities, asset retirement obligations and escrow liabilities. The Company’s tangible net worth covenant is measured based on stockholders’ equity, less intangible assets, as compared to a threshold amount defined in the agreements. The threshold is adjusted over time based on a percentage of net income and the proceeds from the issuance of equity securities.

As of April 30, 2009 and 2008, the Company’s actual and required covenant levels were as follows:


	Actual		Required		Actual		Required
(in thousands)	2010		2010		2009		2009

Minimum fixed charge coverage ratio		2.82		1.50		6.06		1.50
Maximum leverage ratio		0.50		3.00		0.56		3.00
Minimum tangible net worth	$	343,841	$	291,269	$	326,074	$	274,986

The Company’s working capital as of April 30, 2009 and April 30, 2008 was $129,449,000 and $134,045,000, respectively. Working capital levels have been reduced with the reduced level of business activity, and the Company expects working capital to remain at reduced levels over the course of the year. 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 2010.

Operating Activities

Cash provided by operating activities was $9,139,000 for the three months ended April 30, 2009 as compared to cash used in operating activities of $4,010,000 for the same period last year. Although operating earnings have declined from last year, the Company has been able to bring down working capital and defer its normal increase in the first quarter.

Investing Activities

The Company’s capital expenditures, net of disposals, of $12,602,000 for the three months ended April 30, 2009, were split between $9,793,000 to maintain and upgrade its equipment and facilities and $2,809,000 toward the Company’s expansion into unconventional gas exploration and production, including the construction of gas pipeline infrastructure near the Company’s development projects. This compares to equipment spending of $8,656,000 and gas exploration and production spending of $6,828,000 in the same period last year. Over the course of fiscal 2010, we expect equipment and facilities spending to be at or near last year, however unless gas pricing improves, we expect to hold gas exploration and production spending below last year.

Financing Activities

For the three months ended April 30, 2009, the Company had no incremental borrowings under its credit facilities. The Company will make scheduled principal payments on the Senior Notes of $13,333,000 in July 2009, and $6,667,000 in September 2009.

The Company’s contractual obligations and commercial commitments as of April 30, 2009, 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	$	46,667	$	20,000	$	26,667	$	—	$	—
Credit Agreement		—		—		—		—		—
Interest payments		5,636		3,500		2,136		—		—
Software financing obligations		990		482		508		—		—
Operating leases		38,867		13,300		16,636		7,909		1,022
Mineral interest obligations		753		128		412		185		28
Income tax uncertainties		190		190		—		—		—

Total contractual obligations		93,103		37,600		46,359		8,094		1,050

Standby letters of credit		15,499		15,499		—		—		—
Asset retirement obligations		1,321		—		—		—		1,321

Total contractual obligations and commercial commitments	$	109,923	$	53,099	$	46,359	$	8,094	$	2,371

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. 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). Interest payments have been included in the table above based only on outstanding balances and interest rates as of April 30, 2009.

The Company has income tax uncertainties of $8,179,000 at April 30, 2009, that are classified as non-current on the Company’s balance sheet as resolution of these matters is expected to take more than a year. The ultimate timing of resolutions of these items is uncertain, and accordingly the amounts have not been included in the table above.

The Company incurs additional obligations in the ordinary course of operations. These obligations, including but not limited to, 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 discuss 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.

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. Separate full-cost pools are established for each country in which the Company has exploration activities.

The Company is required to review the carrying value of its oil and gas properties under the full cost accounting rules of the SEC. The ceiling limitation is the estimated after-tax future net revenues from proved oil and gas properties discounted at 10%, plus the cost of properties not subject to amortization. If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense. Beginning with our fiscal 2010, application of the ceiling test requires pricing future revenues at the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of reporting period, unless prices are defined by contractual arrangements such as the Company’s fixed-price physical delivery forward sales contracts. Application of the ceiling test 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.

We recorded a ceiling test impairment in the fourth quarter of fiscal 2009. While we did not have a further impairment in the first quarter of fiscal 2010, should gas pricing remain low, and we are not able to replace our forward sales contracts with attractive prices, we could face additional impairments during the course of the year.

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 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 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 and reducing 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 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.

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. In general, the Company records income tax expense during interim periods based on its best estimate of the full year’s effective tax rate. However, income tax expense relating to adjustments to the Company’s liabilities for FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB statement 109” (“FIN48”), is accounted for discretely in the interim period in which it occurs.

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.

New Accounting Pronouncements — See Note 1 of the Notes to Consolidated Financial Statements for a discussion of new accounting pronouncements and their impact on the Company.

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, 2009 Form 10-K and Note 4 of this Form 10-Q. As of April 30, 2009, an instantaneous change in interest rates of one percentage point would not change the Company’s annual interest expense, as we have no variable rate debt outstanding.

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 Company’s affiliates also operate in South America and Mexico. The operations are described in Notes l and 3 of the Notes to Consolidated Financial Statements appearing in the Company’s January 31, 2009, Form 10-K and Note 12 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 of April 30, 2009, the Company held option contracts with an aggregate U.S. dollar notional value of $7,500,000 which are intended to hedge exposure to Australian dollar fluctuations over a period to January 31, 2010.

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 before income taxes for the three months ended April 30, 2009. 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, 2009, the Company held contracts for physical delivery of 5,025,000 million British Thermal Units (“MMBtu”) of natural gas through March 2010 at prices ranging from $7.63 to $10.69 per MMBtu. The estimated fair value of such contracts at April 30, 2009, was $25,003,000. The Company generally intends to maintain contracts in place to cover 50% to 75% of its production, although in response to low gas prices, the Company expects to cover 100% of production in fiscal 2010. We estimate that a ten percent change in the price of natural gas would have impacted income before income taxes by approximately $117,000 for the three months ended April 30, 2009.

ITEM 4. Controls and Procedures

Based on an evaluation of disclosure controls and procedures for the period ended April 30, 2009, 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 April 30, 2009, the Company concluded that its internal control over financial reporting is effective as of April 30, 2009. The Company has not made any significant changes in internal controls or in other factors that could significantly affect internal controls since such evaluation.

PART II

ITEM 1 — Legal Proceedings

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


**	10	(1)	—	Form of Restricted Stock Award Agreement between the Company and management of the Company for use with the 2006 Equity Incentive Plan (with performance vesting)

	10	(2)	—	Amendment No. 4 to Amended and Restated Loan Agreement, dated March 31, 2009, by and among Layne Christensen Company, and Bank of America, N.A. (as successor to LaSalle Bank National Association) (“Bank of America”), as Administrative Agent, and Bank of America and the other lenders a party hereto comprising the Required Lenders (incorporated by reference to Exhibit 10(1) to the Company’s current Report on Form 8-K filed April 2, 2009).

	10	(3)	—	Letter Amendment No. 6 to Master Shelf Agreement, dated March 31, 2009, by and among Layne Christensen Company, Prudential investment Management, Inc., The Prudential Insurance Company of America, Pruco Live Insurance Company, Time Insurance Company and Physicians Mutual Insurance Company (incorporated by reference to Exhibit 10(2) to the Company’s current Report on Form 8-K filed April 2, 2009).

	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.


**		Management contracts or compensatory plans or arrangements required to be identified by Item 14 (a) (3).

b) Reports on Form 8-K

Form 8-K filed on March 30, 2009, related to the Company’s fiscal year ended January 31, 2009 earnings press release and the payment of bonuses to certain named executive officers.

Form 8-K filed on April 2, 3009, related to an amendment to both its Master Shelf Agreement and its Loan Agreement and the goals for certain named executive officers to qualify for a bonus in fiscal 2010.

* * * * * * * * * *

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 2, 2009	/s/ A.B. Schmitt
	A.B. Schmitt, President
	and Chief Executive Officer


DATE: June 2, 2009	/s/ Jerry W. Fanska
	Jerry W. Fanska, Sr. Vice President
	Finance and Treasurer