Edgar Filing: LAYNE CHRISTENSEN CO

Layne Christensen Company 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 October 31, 2005


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 0-20578

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 is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

There were 15,225,240 shares of common stock, $.01 par value per share, outstanding on November 28, 2005.

TABLE OF CONTENTS


PART I
	ITEM 1. Financial Statements
	ITEM 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition
	ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
	ITEM 4. Controls and Procedures
PART II
	ITEM 1 — Legal Proceedings
	ITEM 2 — Changes in Securities
	ITEM 3 — Defaults Upon Senior Securities
	ITEM 4 — Submission of Matters to a Vote of Security Holders
	ITEM 5 — Other Information
	ITEM 6 — Exhibits and Reports on Form 8-K
SIGNATURES
Exhibit 31.1 CEO-302 Certification
Exhibit 31.2 V.P. Finance-Treasurer-302-Certification
Exhibit 32.1 CEO-906 Certification
Exhibit 32.2 V.P. Finance-Treasurer-906 Certification

PART I

ITEM 1. Financial Statements

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


	October 31,			January 31,
	2005			2005
	(unaudited)			(unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	11,099		$	14,408
Customer receivables, less allowance of $5,514 and $4,106, respectively		96,964			54,280
Costs and estimated earnings in excess of billings on uncompleted contracts		42,314			17,143
Inventories		21,275			18,098
Deferred income taxes		11,511			11,664
Income taxes receivable		503			1,186
Other		5,903			4,704

Total current assets		189,569			121,483


Property and equipment:
Land		7,925			6,842
Buildings		17,834			14,342
Machinery and equipment		197,066			176,141
Gas transportation facilities and equipment		10,590			6,413
Oil and gas properties		30,090			20,573
Mineral interest in oil and gas properties		8,052			3,671

		271,557			227,982
Less — Accumulated depreciation and depletion		(145,593	)		(138,526	)

Net property and equipment		125,964			89,456


Other assets:
Investment in affiliates		21,516			20,558
Goodwill		80,899			8,025
Restricted cash		9,000			—
Deferred income taxes		—			2,931
Other		5,657			2,927

Total other assets		117,072			34,441


	$	432,605		$	245,380

See Notes to Consolidated Financial Statements.

— Continued —

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


	October 31,			January 31,
	2005			2005
	(unaudited)			(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	45,364		$	25,758
Accrued compensation		18,456			14,397
Accrued insurance expense		6,095			5,781
Other accrued expenses		11,406			9,930
Income taxes payable		5,044			3,476
Billings in excess of costs and estimated earnings on uncompleted contracts		17,626			7,686

Total current liabilities		103,991			67,028


Noncurrent and deferred liabilities:
Long-term debt		135,500			60,000
Cash purchase price adjustments		14,597			—
Accrued insurance expense		6,544			8,247
Deferred income taxes		249			—
Other		5,488			4,945

Total noncurrent and deferred liabilities		162,378			73,192


Minority interest		—			463


Contingencies

Stockholders’ equity:
Common stock, par value $.01 per share, 30,000,000 shares authorized, 15,225,240 and 12,618,641 shares issued and outstanding, respectively		152			126
Capital in excess of par value		140,922			90,707
Retained earnings		34,777			23,212
Accumulated other comprehensive loss		(9,555	)		(9,067	)
Unearned compensation		(60	)		(281	)


Total stockholders’ equity		166,236			104,697


	$	432,605		$	245,380

See Notes to Consolidated Financial Statements.

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


	Three Months						Nine Months
	Ended October 31,						Ended October 31,
	(unaudited)						(unaudited)
	2005			2004			2005			2004
Revenues	$	113,526		$	91,480		$	316,286		$	253,875
Cost of revenues (exclusive of depreciation shown below)		83,457			66,201			232,326			184,523

Gross profit		30,069			25,279			83,960			69,352
Selling, general and administrative expenses		16,834			15,048			49,196			43,444
Depreciation, depletion and amortization		5,094			3,592			13,122			10,115
Other income (expense):
Equity in earnings of affiliates		972			449			3,244			2,138
Interest		(1,577	)		(841	)		(3,653	)		(2,257	)
Other income, net		471			86			1,004			1,235

Income from continuing operations before income taxes and minority interest		8,007			6,333			22,237			16,909
Income tax expense		3,716			2,827			10,618			8,116
Minority interest		(10	)		1			(50	)		1

Net income from continuing operations before discontinued operations		4,281			3,507			11,569			8,794
Gain (loss) from discontinued operations, net of income tax benefit (expense) of ($3) and $29 for the three months ended October 31, 2005 and 2004, respectively, and ($2) and $125 for the nine months ended October 31, 2005 and 2004, respectively		5			(49	)		(4	)		(211	)

Net income	$	4,286		$	3,458		$	11,565		$	8,583

Basic income (loss) per share:
Net income from continuing operations	$	0.31		$	0.28		$	0.89		$	0.70
Loss from discontinued operations, net of income taxes		—			—			—			(0.02	)

Net income per share	$	0.31		$	0.28		$	0.89		$	0.68


Diluted income (loss) per share:
Net income from continuing operations	$	0.31		$	0.27		$	0.86		$	0.68
Loss from discontinued operations, net of income taxes		—			—			—			(0.02	)

Net income per share	$	0.31		$	0.27		$	0.86		$	0.66


Weighted average shares outstanding		13,697,000			12,574,000			12,988,000			12,556,000
Dilutive stock options		234,000			335,000			515,000			352,000

		13,931,000			12,909,000			13,503,000			12,908,000

See Notes to Consolidated Financial Statements.

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


	Nine Months
	Ended October 31,
	2005			2004
	(unaudited)
Cash flow from operating activities:
Net income	$	11,565		$	8,583
Adjustments to reconcile net income to cash from operations:
Loss from discontinued operations, net of tax		4			211
Depreciation, depletion and amortization		13,122			10,115
Deferred income taxes		1,584			(849	)
Equity in earnings of affiliates		(3,244	)		(2,138	)
Dividends received from affiliates		1,316			1,043
Minority interest		50			(1	)
Gain on sale of joint venture		(1,289	)		—
(Gain) loss from disposal of property and equipment		325			(1,574	)
Changes in current assets and liabilities, net of effects of acquisitions:
Increase in customer receivables		(12,310	)		(14,945	)
(Increase) decrease in costs and estimated earnings in excess of billings on uncompleted contracts		(2,784	)		242
Increase in inventories		(918	)		(1,528	)
(Increase) decrease in other current assets		(779	)		1,710
Increase in accounts payable and accrued expenses		4,259			13,703
Increase (decrease) in billings in excess of costs and estimated earnings on uncompleted contracts		(202	)		359
Other, net		(71	)		55

Cash from continuing operations		10,628			14,986
Cash from (used in) discontinued operations		27			(3,277	)

Cash from operating activities		10,655			11,709

Cash flow used in investing activities:
Additions to property and equipment		(15,413	)		(12,444	)
Additions to gas transportation facilities and equipment		(3,189	)		(1,757	)
Additions to mineral interest in properties		(1,902	)		(1,003	)
Additions to oil and gas properties		(6,989	)		(7,083	)
Proceeds from disposal of property and equipment		849			2,945
Proceeds from sale of business		—			300
Proceeds from sale of joint venture		2,355			—
Acquisition of businesses		(60,351	)		(14,743	)
Acquisition of gas transportation facilities and equipment		(1,445	)		(654	)
Acquisition of oil and gas working interest		(4,704	)		(2,728	)
Investment in joint ventures		(69	)		(274	)

Cash used in investing activities		(90,858	)		(37,441	)

Cash flow from financing activities:
Net borrowings (repayments) under revolving facility		75,500			(2,000	)
Issuance of long-term debt		—			20,000
Debt issuance costs		(605	)		(30	)
Payments on DrillCorp promissory note		(960	)		(1,380	)
Payments on notes receivable from management stockholders		—			28
Issuance of common stock		3,216			239

Cash from financing activities		77,151			16,857

Effects of exchange rate changes on cash		(257	)		755

Net decrease in cash and cash equivalents		(3,309	)		(8,120	)
Cash and cash equivalents at beginning of period		14,408			21,602

Cash and cash equivalents at end of period	$	11,099		$	13,482

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Accounting Policies and Basis of Presentation

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, 2005 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.

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

Revenue Recognition — Revenue is recognized on large, long-term contracts using the percentage of completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues and gross profit in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. Revenue is recognized on smaller, short-term contracts using the completed contract method. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined.

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

Other Long-lived Assets — In evaluating the fair value and future benefits of long-lived assets, including the Company’s gas transportation facilities and equipment,

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

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

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

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

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

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

Reserve Estimates — The Company’s estimates of coalbed methane gas reserves, by necessity, are projections based on geologic and engineering data, and there are

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

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

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

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

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

Stock-based compensation — Stock-based compensation may be accounted for either based on the estimated fair value of the awards at the date they are granted (the “SFAS 123 Method”) or based on the difference, if any, between the market price of the stock at the date of grant and the amount the employee must pay to acquire the stock (the “APB 25 Method”). The Company uses the APB 25 Method to account for its stock-based compensation programs and recognized no compensation expense under this method in the nine months ended October 31, 2005 and 2004.

Pro forma net income and earnings per share for the three and nine months ended October 31, 2005 and 2004, determined as if the SFAS 123 Method had been applied, are presented in the following table (in thousands, except per share amounts):


	Three Months						Nine Months
	Ended October 31,						Ended October 31,
	2005			2004			2005			2004
Net income, as reported	$	4,286		$	3,458		$	11,565		$	8,583
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax		(96	)		(14	)		(218	)		(48	)

Pro forma net income	$	4,190		$	3,444		$	11,347		$	8,535

Income per share:
Basic — as reported	$	0.31		$	0.28		$	0.89		$	0.68

Basic — pro forma	$	0.31		$	0.27		$	0.87		$	0.68

Diluted — as reported	$	0.31		$	0.27		$	0.86		$	0.66

Diluted — pro forma	$	0.30		$	0.27		$	0.84		$	0.66

The amounts paid for income taxes, net of refunds, and interest are as follows (in thousands):


	Nine Months Ended October 31,
	2005		2004
Income taxes	$	3,756	$	1,099
Interest		3,526		2,132

2. Acquisitions

On September 28, 2005 (the “Closing Date”), the Company acquired 100% of the outstanding stock of Reynolds, Inc. (“Reynolds”), a privately held company and a major supplier of products and services to the water and wastewater industries. The acquisition will expand the capabilities of the Company’s Water Resources division in the areas of water and wastewater infrastructure. Reynolds’ primary service lines include designing and building of water and wastewater treatment plants, water and wastewater transmission lines, cured in place pipe (“CIPP”) services for sewer rehabilitation, water supply wells and Ranney collector wells. The purchase price for Reynolds was $112,356,000, consisting of $60,000,000 cash, 2,222,216 shares of Layne common stock (valued at $45,053,000), cash purchase price

adjustments of $6,120,000 (to be paid in future periods) and costs of $1,183,000. Layne common stock was valued in the transaction based upon a five-day average of the closing price of the stock two days before and two days after the terms of the acquisition were agreed to and publicly announced. The cash purchase price adjustments consist primarily of an adjustment to be paid based on the amount by which working capital at the Closing Date exceeded a threshold amount established in the purchase agreement. This amount will be paid to the Reynolds shareholders beginning twenty-four months following the Closing Date based on the collection of certain contract retainage amounts. Of the cash and stock consideration, $9,000,000 and 333,333 shares of Layne common stock were placed in escrow to secure certain representations, warranties and indemnifications under the purchase agreement (the “Escrow Fund”). The Escrow Fund will be released to the Reynolds shareholders twenty four months following the Closing Date, subject to any pending claims. The cash portion of the Escrow Fund is recorded in the Company’s consolidated balance sheet as “Restricted cash”.

In addition, there is contingent consideration up to a maximum of $15,000,000 (the “Earnout Amount”), which is based on Reynolds operating performance over a period of thirty-six months following the Closing Date (the “Earnout Period”). The Earnout Amount is based on a multiple of Reynolds’ earnings before interest, taxes, depreciation and amortization which exceed a threshold amount during the Earnout Period. If earned, the contingent payment will be paid 60% in cash and 40% in Layne common stock, subject to stockholder approval of the shares to be issued, if required. Any shares not approved for issuance will be paid in cash.

The purchase price has been allocated based primarily on Reynolds’ historical cost basis of assets and liabilities, and accordingly, the allocations are subject to revisions when the Company receives final information regarding the fair value of the assets and liabilities acquired, including appraisals and other analyses. Such revisions may be significant and will be recorded by the Company as further adjustments to the purchase price allocation.

Based on the Company’s preliminary allocation of the purchase price, the acquisition had the following effect on the Company’s consolidated financial position (in thousands):


Working capital	$	21,597
Long-lived and other non-current assets		17,885
Goodwill		72,874

Total purchase price	$	112,356

The results of operations of Reynolds have been included in the Company’s consolidated Statements of Income as of the Closing Date. Assuming Reynolds had been acquired as of the beginning of the period, the unaudited proforma consolidated revenues, net income from continuing operations, net income and net income per share would have been as follows (in thousands, except per share data):


	Three Months Ended				Nine Months Ended
	October 31,				October 31,
	2005		2004		2005		2004
	(unaudited)		(unaudited)		(unaudited)		(unaudited)
Revenues	$	155,135	$	138,799	$	454,052	$	386,177
Net income from continuing operations		4,882		3,902		14,829		9,605
Net income		4,887		3,853		14,825		9,394
Basic earnings per share from continuing operations	$	0.31	$	0.26	$	0.97	$	0.65

Diluted earnings per share from continuing operations	$	0.30	$	0.26	$	0.94	$	0.63

Basic earnings per share	$	0.31	$	0.26	$	0.97	$	0.64

Diluted earnings per share	$	0.30	$	0.25	$	0.94	$	0.62

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

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


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

Total purchase price	$	6,406

3. Discontinued Operations

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

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

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the results of operations for Toledo and Layne Canada have been classified as discontinued operations. Revenues and loss from discontinued operations for the three and nine months ended October 31, 2005 and 2004 were as follows (in thousands):


	Three Months Ended					Nine Months Ended
	October 31,					October 31,
	2005		2004			2005			2004
Revenues:
Canada	$	—	$	—		$	—		$	—
Toledo		—		—			—			—

Total	$	—	$	—		$	—		$	—

Income (loss) from discontinued operations before income taxes:
Canada	$	—	$	(78	)	$	(9	)	$	(294	)
Toledo		8		—			7			(42	)

Total	$	8	$	(78	)	$	(2	)	$	(336	)

4. Indebtedness

On July 31, 2003, the Company entered into an agreement (“Master Shelf Agreement”) whereby it could issue up to $60,000,000 in unsecured notes. Upon closing, the Company issued $40,000,000 of notes (“Series A Senior Notes”) under the Master Shelf Agreement. The Series A Senior Notes bear a fixed interest rate of 6.05% and are due on July 31, 2010, with annual principal payments of $13,333,000 beginning July 31, 2008. Proceeds from the issuance were used to refinance borrowings outstanding under the Company’s previous term loan and revolving credit facility. The Company issued an additional $20,000,000 of notes under the Master Shelf Agreement in October 2004 (“Series B Senior Notes”). The Series B Senior Notes bear a fixed interest rate of 5.40% and are due on September 29, 2011, with annual principal payments of $6,667,000 beginning September 29, 2009. Proceeds of the issuance were used to finance the acquisition of Beylik Drilling and Pump Services, Inc. and general corporate purposes. Concurrent with the acquisition of Reynolds, the Company amended the Master Shelf Agreement to increase the amount of senior notes available to be issued from $60,000,000 to $100,000,000, thus, creating an available facility amount of $40,000,000, and reinstated and extended the available issuance period to September 15, 2007.

Also, concurrent with the acquisition of Reynolds, the Company expanded its existing revolving credit facility with LaSalle Bank National Association, as Administrative Agent, and a group of additional banks by entering into an Amended and Restated Loan Agreement (the “Credit Agreement”) with LaSalle Bank National Association, as Administrative Agent and as Lender (the “Administrative Agent”), and the other Lenders listed therein (the “Lenders”), which increased the Company’s revolving loan commitment from $40,000,000 to $130,000,000, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit). Approximately $80 million of the facility was used to pay the cash portion of the acquisition of Reynolds and refinance the outstanding borrowings under the previous credit agreement. The Credit Agreement provides for interest at variable rates equal to, at the Company’s option, a LIBOR rate plus 1.00% to 2.00%, or a base rate, as defined in the Credit Agreement plus up to 0.50%, depending upon the Company’s leverage ratio. The Credit Agreement is unsecured and is due and payable September 28, 2010. On October 31, 2005, there were letters of credit of $10,474,000 and borrowings of $75,500,000 outstanding on the Credit Agreement resulting in available capacity of $44,026,000.

The Master Shelf Agreement and the Credit Agreement contain certain covenants including restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions, transfer or sale of assets, transactions with

affiliates, payment of dividends and certain financial maintenance covenants, including among others, fixed charge coverage, maximum debt to EBITDA and minimum tangible net worth. The Company was in compliance with its covenants as of October 31, 2005.

Debt outstanding as of October 31, 2005 and January 31, 2005 was as follows (in thousands):


	October 31,		January 31,
	2005		2005
Long-term debt:
Credit Agreement	$	75,500	$	—
Senior Notes		60,000		60,000


Total long-term debt	$	135,500	$	60,000

5. Derivatives

The Company’s energy division is exposed to fluctuations in the price of natural gas and has entered into fixed-price physical delivery contracts to manage natural gas price risk for a portion of its production. As of October 31, 2005, the Company had committed to deliver 2,071,000 million British Thermal Units (“MMBtu”) of natural gas through March 2007. The prices on these contracts range from $5.43 to $9.48 per MMBtu.

The fixed-price physical delivery contracts will result in the physical delivery of natural gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts. The estimated fair value of such contracts at October 31, 2005 and January 31, 2005 was $2,027,000 and $213,000, respectively.

Additionally, the Company has foreign operations that have significant costs denominated in foreign currencies, and thus is exposed to risks associated with changes in foreign currency exchange rates. At any point in time, the Company might use various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with forecasted expatriate labor costs and purchases of operating supplies.

The Company held option contracts with an aggregate U.S. dollar notional value of $3,000,000 as of October 31, 2005 (none as of January 31, 2005) to hedge the risks associated with forecasted Australian dollar denominated costs in its African operations. The contracts held as of October 31, 2005 settle in various increments through January 2006. The fair value of the instruments of $20,000 at October 31, 2005 was recorded in other current assets and in accumulated other comprehensive income net of income taxes of $8,000. Aggregate losses of $60,000 and $179,000 on foreign currency hedging transactions were recognized for the nine months ended October 31, 2005 and 2004 as the forecasted transactions being hedged occurred and were recorded primarily in cost of revenues in the Company’s Consolidated Statements of Income.

6. Other Comprehensive Income (Loss)

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


	Three Months						Nine Months
	Ended October 31,						Ended October 31,
	2005			2004			2005			2004
Net income	$	4,286		$	3,458		$	11,565		$	8,583
Other comprehensive income (loss), net of taxes:
Foreign currency translation adjustments		(36	)		2,685			(346	)		550
Change in unrecognized pension liability		—			—			(154	)		—
Unrealized gain (loss) on foreign exchange contracts		(55	)		(3	)		12			(800	)

Other comprehensive income	$	4,195		$	6,140		$	11,077		$	8,333

The components of accumulated other comprehensive loss for the nine months ended October 31, 2005 and 2004 are as follows (in thousands):


							Unrealized		Accumulated
	Cumulative			Unrecognized			Gain		Other
	Translation			Pension			on Exchange		Comprehensive
	Adjustment			Liability			Contracts		Loss
Balance, February 1, 2005	$	(7,165	)	$	(1,902	)	$	—	$	(9,067	)
Period change		(346	)		(154	)		12		(488	)

Balance, October 31, 2005	$	(7,511	)	$	(2,056	)	$	12	$	(9,555	)


							Unrealized			Accumulated
	Cumulative			Unrecognized			Gain			Other
	Translation			Pension			on Exchange			Comprehensive
	Adjustment			Liability			Contracts			Loss
Balance, February 1, 2004	$	(8,701	)	$	(1,784	)	$	856		$	(9,629	)
Period change		550			—			(800	)		(250	)

Balance, October 31, 2004	$	(8,151	)	$	(1,784	)	$	56		$	(9,879	)

7. Employee Benefit Plans

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

Net periodic pension cost for the three and nine months ended October 31, 2005 and 2004 includes the following components (in thousands):


	Three Months						Nine Months
	Ended October 31,						Ended October 31,
	2005			2004			2005			2004
Service cost	$	18		$	17		$	54		$	51
Interest cost		109			110			327			330
Expected return on assets		(121	)		(113	)		(363	)		(339	)
Net amortization		67			48			201			144

Net periodic pension cost	$	73		$	62		$	219		$	186

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

The Company also provides supplemental retirement benefits to its chief executive officer. Benefits are computed based on the compensation earned during the highest five consecutive years of employment reduced for a portion of Social Security benefits and an annuity equivalent of the chief executive’s defined contribution plan balance. The Company does not contribute to the plan or maintain any investment assets related to the expected benefit obligation. The Company has recognized the full amount of its actuarially determined pension liability. Net
periodic pension cost of the supplemental retirement benefits for the three and nine months ended October 31, 2005 and 2004 include the following components (in thousands):


	Three Months				Nine Months
	Ended October 31,				Ended October 31,
	2005		2004		2005		2004
Service cost	$	30	$	25	$	90	$	75
Interest cost		19		18		57		54

Net periodic pension cost	$	49	$	43	$	147	$	129

8. Operating Segments

The Company is a multinational company which provides sophisticated services and related products to a variety of markets. The Company is organized into discrete divisions based on its primary product lines. The Company’s reportable segments are defined as follows:

Water Resources Division

This division provides a full line of water-related services and products including hydrological studies, site selection, well design, drilling and well development, pump installation, and repair and maintenance. The division’s offerings include design and construction of water treatment facilities and the manufacture and sale of products to treat volatile organics and other contaminants such as nitrates, iron, manganese, arsenic, radium and radon in groundwater. The division also offers environmental services to assess and monitor groundwater contaminants.

With the acquisition of Reynolds in September 2005, the division expanded its capabilities in the areas of the designing and building of water and wastewater treatment plants, Ranney collector wells, sewer rehabilitation and water and wastewater transmission lines.

Mineral Exploration Division

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

Geoconstruction Division

This division focuses on services that improve soil stability, primarily jet grouting, grouting, vibratory ground improvement, drilled micropiles, stone columns, anchors and tiebacks. The division also manufactures a line of high-pressure pumping equipment used in grouting operations and geotechnical drilling rigs used for directional drilling.

Energy Division

This division focuses on exploration and production of coalbed methane (“CBM”) properties in the mid-continent region of the United States. Historically, the division has also included two small specialty energy services companies. The division’s strategy has changed to focus entirely on CBM exploration and development. As a result, the energy service companies have been classified in “Other” below.

Other

Other includes any specialty operations not included in one of the other divisions.

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


	Three Months					Nine Months
	Ended October 31,					Ended October 31,
	2005		2004			2005		2004
Revenues
Water resources	$	69,423	$	51,852		$	183,810	$	145,058
Mineral exploration		30,764		27,448			94,433		77,690
Geoconstruction		8,208		10,475			26,717		27,514
Energy		3,733		1,042			7,836		1,965
Other		1,398		663			3,490		1,648

Total revenues	$	113,526	$	91,480		$	316,286	$	253,875


Equity in earnings of affiliates
Mineral exploration	$	874	$	474		$	2,838	$	2,137
Geoconstruction		98		(25	)		406		1

Total equity in earnings of affiliates	$	972	$	449		$	3,244	$	2,138


	Three Months						Nine Months
	Ended October 31,						Ended October 31,
	2005			2004			2005			2004
Income from continuing operations before income taxes and minority interest
Water resources	$	6,485		$	7,167		$	16,752		$	17,497
Mineral exploration		3,348			3,027			13,001			10,254
Geoconstruction		823			918			2,585			2,437
Energy		1,009			(533	)		1,426			(1,787	)
Other		230			(92	)		426			143
Unallocated corporate expenses		(2,311	)		(3,313	)		(8,300	)		(9,378	)
Interest		(1,577	)		(841	)		(3,653	)		(2,257	)

Total income from continuing operations before income taxes and minority interest	$	8,007		$	6,333		$	22,237		$	16,909


Geographic Information:
Revenues
North America	$	94,567		$	72,711		$	253,344		$	197,771
Africa/Australia		16,816			17,240			55,737			50,623
Other foreign		2,143			1,529			7,205			5,481

Total revenues	$	113,526		$	91,480		$	316,286		$	253,875

9. Contingencies

The Company’s drilling activities involve certain operating hazards that can result in personal injury or loss of life, damage and destruction of property and equipment, damage to the surrounding areas, release of hazardous substances or wastes and other damage to the environment, interruption or suspension of drill site operations and loss of revenues and future business. The magnitude of these operating risks is amplified when the Company, as is frequently the case, conducts a project on a fixed-price, “turnkey” basis where the Company delegates certain functions to subcontractors but remains responsible to the customer for the subcontracted work. In addition, the Company is exposed to potential liability under foreign, federal, state and local laws and regulations, contractual indemnification agreements or otherwise in connection with its provision of 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 for 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, in the aggregate, have a material adverse effect upon its business or consolidated financial position, results of operations or cash flows.

10. New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123R (revised December 2004), “Share-Based Payment” which requires the recognition of all share-based payments in the financial statements and establishes a fair-value measurement of the associated costs. SFAS No. 123R will be effective for the first quarter of fiscal 2007 and is not expected to have a significant impact on the results of operations or financial position of the Company.

In December 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4”. SFAS No. 151 clarifies that the allocation of fixed production overhead to inventory is based on normal capacity. Abnormal amounts of idle facility, excess freight, handling costs and spoilage should be recognized as a current period charge. SFAS No. 151 is effective February 1, 2006 and is not expected to have a significant impact on the results of operations or financial position of the Company.

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

Cautionary Language Regarding Forward-Looking Statements

This Form 10-Q contains 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 are indicated by words or phrases such as “anticipate,” “estimate,” “project,” “believe,” “intend,” “expect,” “plan” 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 metals, unanticipated slowdowns in the Company’s major markets, 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						Nine Months						Period-to-Period
	Ended						Ended						Change
	October 31,						October 31,						Three			Nine
	2005			2004			2005			2004			Months			Months
Revenues:
Water resources		61.2	%		56.7	%		58.1	%		57.1	%		33.9	%		26.7	%
Mineral exploration		27.1			30.0			29.9			30.6			12.1			21.6
Geoconstruction		7.2			11.5			8.4			10.9			(21.6	)		(2.9	)
Energy		3.3			1.1			2.5			0.8			258.3			298.8
Other		1.2			0.7			1.1			0.6			110.9			111.8

Total net revenues		100.0	%		100.0	%		100.0	%		100.0	%		24.1			24.6
Cost of revenues		73.5			72.4			73.5			72.7			26.1			25.9

Gross profit		26.5			27.6			26.5			27.3			18.9			21.1
Selling, general and administrative expenses		14.8			16.4			15.6			17.1			11.9			13.2
Depreciation, depletion and amortization		4.5			3.9			4.1			4.0			41.8			29.7
Other income (expense):
Equity in earnings of affiliates		0.9			0.5			1.0			0.8			116.5			51.7
Interest		(1.4	)		(0.9	)		(1.1	)		(0.8	)		87.5			61.9
Other income, net		0.4			—			0.3			0.5			447.7			(18.7	)

Income from continuing operations before income taxes and minority interest		7.1			6.9			7.0			6.7			26.4			31.5
Income tax expense		3.3			3.1			3.3			3.2			31.4			30.8
Minority interest		—			—			—			—			*			*

Net income from continuing operations before discontinued operations		3.8			3.8			3.7			3.5			22.1			31.6
Loss from discontinued operations, net of income taxes		—			—			—			(0.1	)		*			*

Net income		3.8	%		3.8	%		3.7	%		3.4	%		23.9			34.7


*		Not meaningful.


	Three Months						Nine Months
	Ended October 31,						Ended October 31,
	2005			2004			2005			2004
Revenues
Water resources	$	69,423		$	51,852		$	183,810		$	145,058
Mineral exploration		30,764			27,448			94,433			77,690
Geoconstruction		8,208			10,475			26,717			27,514
Energy		3,733			1,042			7,836			1,965
Other		1,398			663			3,490			1,648

Total revenues	$	113,526		$	91,480		$	316,286		$	253,875


Equity in earnings of affiliates
Mineral exploration	$	874		$	474		$	2,838		$	2,137
Geoconstruction		98			(25	)		406			1

Total equity in earnings of affiliates	$	972		$	449		$	3,244		$	2,138


Income from continuing operations before income taxes and minority interest
Water resources	$	6,485		$	7,167		$	16,752		$	17,497
Mineral exploration		3,348			3,027			13,001			10,254
Geoconstruction		823			918			2,585			2,437
Energy		1,009			(533	)		1,426			(1,787	)
Other		230			(92	)		426			143
Unallocated corporate expenses		(2,311	)		(3,313	)		(8,300	)		(9,378	)
Interest		(1,577	)		(841	)		(3,653	)		(2,257	)

Total income from continuing operations before income taxes and minority interest	$	8,007		$	6,333		$	22,237		$	16,909

Results of Operations

Revenues for the three months ended October 31, 2005 increased $22,046,000, or 24.1%, to $113,526,000 while revenues for the nine months ended October 31, 2005 increased $62,411,000, or 24.6%, to $316,286,000 from the same periods last year. See further discussion of results of operations by division below.

Gross profit as a percentage of revenues was 26.5% for the three and nine months ended October 31, 2005 compared to 27.6% and 27.3% for the three and nine months ended October 31, 2004. The decreases in gross profit percentage were primarily the result of reduced margins in the water resources division arising from a change in product mix with the acquisition of Reynolds, Inc. (“Reynolds”) and higher than expected costs on certain water supply contracts. These decreases were partially offset by improved margins in the energy division due to the increased sales of natural gas as a result of increased production and natural gas pricing.

Selling, general and administrative (“SG&A”) expenses were $16,834,000 for the three months ended October 31, 2005 and $49,196,000 for the nine months ended October 31, 2005 (14.8% and 15.6% of revenues, respectively), compared to $15,048,000 and $43,444,000 for the three and nine months ended October 31, 2004 (16.4% and 17.1% of revenues, respectively). The increases for both the three and nine month periods were primarily SG&A costs assumed in the acquisitions of

Reynolds in September 2005, Beylik Drilling and Pump Service, Inc. (“Beylik”) in October 2004, expansion of the Company’s water treatment capabilities and additional accrued incentive compensation expense as a result of improved profitability of the minerals exploration division.

Depreciation, depletion and amortization increased to $5,094,000 and $13,122,000 for the three and nine months ended October 31, 2005, compared to $3,592,000 and $10,115,000 for the same periods last year. The increase for both periods was primarily attributable to the increased depreciation associated with the property and equipment purchased in the Reynolds and Beylik acquisitions and increased depletion from the increase in production of natural gas from the Company’s coalbed methane operations.

Equity in earnings of affiliates increased to $972,000 for the three months ended October 31, 2005 and increased to $3,244,000 for the nine months ended October 31, 2005, compared to $449,000 and $2,138,000 for the same periods in the prior year. The increases were due to improved earnings in Latin America from increased mineral exploration activity and income from a joint venture in the geoconstruction division.

Interest expense was $1,577,000 and $3,653,000 for the three and nine months ended October 31, 2005, compared to $841,000 and $2,257,000 for same periods last year. The increase was a result of an increase in the Company’s average borrowings during the year to fund the Reynolds and Beylik acquisitions and ongoing capital expenditures.

Other income, net was income of $471,000 for the three months ended October 31, 2005, compared to income of $86,000 in the prior year, and income of $1,004,000 for the nine months ended October 31, 2005, compared to income of $1,235,000 in the prior year. Other income, net consists primarily of gains and losses on the dispositions of non-strategic assets.

The Company’s effective tax rate was 46.4% and 47.75% for the three and nine months ended October 31, 2005, compared to 44.6% and 48.0% for the three and nine months ended October 31, 2004. 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 Resources Division
(in thousands)


	Three Months Ended				Nine Months Ended
	October 31,				October 31,
	2005		2004		2005		2004
Revenues	$	69,423	$	51,852	$	183,810	$	145,058
Income from continuing operations before income taxes		6,485		7,167		16,752		17,497

Water resources revenue increased 33.9% to $69,423,000 for the three months ended October 31, 2005 and 26.7% to $183,810,000 for the nine months ended October 31, 2005 compared to $51,852,000 and $145,058,000 for the three and nine months ended October 31, 2004. The increases were primarily attributable to the Reynolds and Beylik acquisitions and results from the Company’s water treatment initiatives.

Income from continuing operations for the water resources division was $6,485,000 and $16,752,000 for the three and nine months ended October 31, 2005 compared to $7,167,000 and $17,497,000 for the three and nine months ended October 31, 2004.

The decreases in income from continuing operations were primarily the result of higher than expected costs on certain water supply contracts and additional costs associated with the introduction of membrane and other technologies to the division’s water treatment initiatives. In addition to these factors, the decrease in income from continuing operations as a percentage of revenues was also attributable to a change in product mix with the Reynolds acquisition.

The above results for the Water Resources division include the results of operations of Reynolds, Inc. from the date of acquisition, September 28, 2005. Reynolds contributed $14,932,000 of revenue and $858,000 of income before interest and income taxes for the period.

Mineral Exploration Division
(in thousands)


	Three Months Ended				Nine Months Ended
	October 31,				October 31,
	2005		2004		2005		2004
Revenues	$	30,764	$	27,448	$	94,433	$	77,690
Income from continuing operations before income taxes		3,348		3,027		13,001		10,254

Mineral exploration revenues increased 12.1% to $30,764,000 and 21.6% to $94,433,000 for the three and nine months ended October 31, 2005 compared to revenues of $27,448,000 and $77,690,000 for the three and nine months ended October 31, 2004. The increase for the periods was primarily attributable to continued strength in worldwide exploration activity as a result of the relatively high gold and base metal prices.

Income from continuing operations for the mineral exploration division was $3,348,000 and $13,001,000 for the three and nine months ended October 31, 2005, compared to $3,027,000 and $10,254,000 for the three and nine months ended October 31, 2004. The increases in income from continuing operations were primarily attributable to the impact of increased exploration activity on the Company and its Latin American affiliates.

Geoconstruction Division
(in thousands)


	Three Months Ended				Nine Months Ended
	October 31,				October 31,
	2005		2004		2005		2004
Revenues	$	8,208	$	10,475	$	26,717	$	27,514
Income from continuing operations before income taxes		823		918		2,585		2,437

Geoconstruction revenues decreased 21.6% to $8,208,000 and 2.9% to $26,717,000 for the three and nine months ended October 31, 2005 compared to $10,475,000 and $27,514,000 for the three and nine months ended October 31, 2004. The decreases in revenues for both periods were primarily the result of larger than historically normal projects performed in the prior year, which were only partially replaced in the current year.

Income from continuing operations for the geoconstruction division was $823,000 for the three months ended October 31, 2005 and $2,585,000 for the nine months ended October 31, 2005, compared to $918,000 and $2,437,000 for the three and nine months ended October 31, 2004. Income for the three and nine months ended October 31, 2005, included incremental equity earnings of the division’s joint venture of

$98,000 and $406,000, respectively. Excluding such earnings, the decrease in income from continuing operations was consistent with the change in revenues for the periods.

Energy Division
(in thousands)


	Three Months Ended					Nine Months Ended
	October 31,					October 31,
	2005		2004			2005		2004
Revenues	$	3,733	$	1,042		$	7,836	$	1,965
Income (loss) from continuing operations before income taxes		1,009		(533	)		1,426		(1,787	)

Energy revenues increased 258.3% to $3,733,000 and 298.8% to $7,836,000 for the three and nine months ended October 31, 2005, compared to revenues of $1,042,000 and $1,965,000 for the three and nine months ended October 31, 2004. The increase in revenues was primarily attributable to increased production from the Company’s coalbed methane properties and higher natural gas prices.

Income from continuing operations for the energy division was $1,009,000 and $1,426,000 for the three and nine months ended October 31, 2005, compared to losses of $533,000 and $1,787,000 for the three and nine months ended October 31, 2004. The increases in income were due to the increase in production, higher natural gas prices and certain overhead cost reductions.

Unallocated Corporate Expenses

Unallocated corporate expenses were $2,311,000 and $8,300,000 for the three and nine months ended October 31, 2005 compared to $3,313,000 and $9,378,000 for the three and nine months ended October 31, 2004. The decrease for the three-month period was primarily due to lower professional fees for Sarbanes-Oxley requirements, which are being incurred on a more ratable basis in the current year. The prior year nine-month period includes charges in the second quarter related to the write-down of non-strategic assets.

Changes in Financial Condition

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

The Company maintains an agreement (the “Master Shelf Agreement”) whereby it has $100,000,000 of unsecured notes available to be issued before September 15, 2007. At October 31, 2005, the Company has $60,000,000 in notes outstanding under the Master Shelf Agreement. Additionally, the Company holds a revolving credit facility (the “Credit Agreement”) composed of an unsecured $130,000,000 revolving facility, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit). Amounts outstanding under the Credit Agreement are due and payable September 28, 2010. At October 31, 2005, the Company had $75,500,000 outstanding under the Credit Agreement(see Note 4 of the Notes to Consolidated Financial Statements). The Company was in compliance with its financial covenants at October 31, 2005 and expects to remain in compliance through the foreseeable future.

The Company’s working capital as of October 31, 2005 and January 31, 2005 was $85,578,000 and $54,455,000, respectively. The increase in working capital at October 31, 2005 was primarily attributable to the increase in the balance of accounts receivable as a result of the growth in revenues and working capital acquired in the Reynolds acquisition. The Company believes it will have sufficient cash from operations and access to credit facilities to meet the Company’s operating cash requirements and to fund its budgeted capital expenditures for fiscal 2007.

Operating Activities

Cash provided from operating activities, excluding discontinued operations, was $10,628,000 and $14,986,000 for the nine months ended October 31, 2005 and 2004, respectively. The decrease in cash provided from operating activities was primarily attributable to the increased working capital necessitated by the increased revenue levels. The cash used in discontinued operations for the nine months ended October 31, 2004 included the payment of lease termination liabilities and closing costs related to the sale of Layne Canada, partially offset by collection of receivables related to Layne Canada.

Investing Activities

In September 2005, the Company acquired all of the outstanding stock of Reynolds for total consideration of $60,000,000 in cash and approximately 2.2 million shares of common stock of the Company. Reynolds is a major supplier of products and services to the water and wastewater industries including the design/build of water and wastewater treatment plants, water supply wells, Ranney collector wells, water intakes and water and wastewater transmission lines.

In October 2005, the Company acquired certain oil and gas working interests and gas transportation facilities and equipment from a working interest partner for $6,149,000 in cash.

The Company’s capital expenditures of $27,493,000 for the nine months ended October 31, 2005 were directed primarily toward the Company’s expansion and upgrading of equipment and facilities primarily in the energy, mineral exploration and water divisions. Expenditures for the year are budgeted to be approximately $30,000,000.

Financing Activities

For the nine months ended October 31, 2005, the Company borrowed $75,500,000 under its credit facilities primarily for the Reynolds acquisition, working capital requirements and to fund capital expenditures. Additionally, proceeds of $3,216,000 were received from issuance of common stock related to the exercise of stock options. The increase in the exercise of stock options was due to increases in the Company’s stock price and a number of options with impending expiration dates.

The Company’s contractual obligations and commercial commitments are summarized as follows:


	Payments/Expiration by Period
			Less than						More than
	Total		1year		1-3years		4-5years		5years
Contractual obligations and other commercial commitments
Senior notes	$	60,000	$	—	$	13,333	$	40,000	$	6,667
Credit agreement		75,500		—		—		75,500		—
Operating leases		22,287		10,122		10,277		1,888		—
Mineral interest obligations		517		106		292		96		23

Total contractual cash obligations		158,304		10,228		23,902		117,484		6,690


Standby letters of credit		10,474		10,474		—		—		—
Asset retirement obligations		573		—		—		—		573

Total contractual obligations and commercial commitments	$	169,351	$	20,702	$	23,902	$	117,484	$	7,263

The Company expects to meet its contractual cash obligations in the ordinary course of operations, and that the standby letters of credit will be renewed in connection with its annual insurance renewal process. Payments related to the credit agreement and senior notes do not include interest payments. Interest is payable on the senior notes at fixed interest rates of 6.05% and 5.40%. Interest is payable on the credit agreement at variable interest rates equal to, at the Company’s option, a LIBOR rate plus 1.00% to 2.00%, or a base rate, as defined in the Credit Agreement plus up to 0.50%, depending on the Company’s leverage ratio (See Note 4 of the Notes to Consolidated Financial Statements).

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

Critical Accounting Policies and Estimates

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

Our accounting policies are more fully described in Note 1 to the financial statements, located elsewhere in this Form 10-Q and in Note 1 of our Annual Report

on Form 10-K for the year ended January 31, 2005. 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.

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

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

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

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

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

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

The Company centrally manages its debt portfolio considering overall financing strategies and tax consequences. A description of the Company’s debt is in Note 12 of the Notes to Consolidated Financial Statements appearing in the Company’s January 31, 2005 Form 10-K and Note 4 of this Form 10-Q. As of October 31, 2005, $60,000,000 of the Company’s long-term debt outstanding carries a fixed-rate and $75,500,000 is variable rate debt. An instantaneous change in interest rates of one percentage point would change the Company’s annual interest expense by $755,000.

Operating in international markets involves exposure to possible volatile movements in currency exchange rates. Currently, the Company’s primary international operations are in Australia, Africa, Mexico and Italy. The operations are described in Note 1 of the Notes to Consolidated Financial Statements appearing in the Company’s January 31, 2005 Form 10-K and Note 8 of this Form 10-Q. The majority of the Company’s contracts in Africa and Mexico are U.S. dollar based, providing a natural reduction in exposure to currency fluctuations. The Company also may utilize various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with fluctuating currency exchange rates (see Note 5 of the Notes to Consolidated Financial Statements).

As currency exchange rates change, translation of the income statements of the Company’s international operations into U.S. dollars may affect year-to-year comparability of operating results. We estimate that a ten percent change in foreign exchange rates would not have significantly impacted income from continuing operations for the nine months ended October 31, 2005 and 2004. 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 natural gas production. The price of natural gas is volatile and the Company has entered into fixed-price physical contracts covering a portion of its production to manage price fluctuations and to achieve a more predictable cash flow. As of October 31, 2005, the Company held contracts for physical delivery of 2,071,000 million British Thermal Units (“MMBtu”) of natural gas at prices ranging from $5.43 to $9.48 per MMBtu. The estimated fair value of such contracts at October 31, 2005 was $2,027,000.

We estimate that a ten percent change in the price of natural gas would have impacted income from continuing operations before taxes by approximately $784,000 for the nine months ended October 31, 2005.

ITEM 4. Controls and Procedures

Based on an evaluation of disclosure controls and procedures for the period ended October 31, 2005 conducted under the supervision and with the participation of the Company’s management, including the Principal Executive Officer and the Principal Financial Officer, the Company concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

Based on an evaluation of internal controls over financial reporting conducted under the supervision and the participation of the Company’s management, including the Principal Executive Officer and Principal Financial Officer, for the period ended October 31, 2005, the Company concluded that its internal control over financial reporting is effective as of October 31, 2005. The Company has not made any significant changes in internal controls or in other factors that could significantly affect internal controls since such evaluation. The Company excluded from its assessment any changes in internal control over financial reporting at the Reynolds, Inc. business, which was acquired on September 28, 2005, and whose financial statements reflect total assets and revenues constituting 17% and 5%, respectively, of the related consolidated financial statement amounts as of and for the nine months ended October 31, 2005. The Company will include Reynolds, Inc. in its evaluation of the design and effectiveness of internal control over financial reporting as of January 31, 2007.

PART II

ITEM 1 — Legal Proceedings

NONE

ITEM 2 — Changes in Securities

NOT APPLICABLE

ITEM 3 — Defaults Upon Senior Securities

NOT APPLICABLE

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

NONE

ITEM 5 — Other Information

NONE

ITEM 6 — Exhibits and Reports on Form 8-K

a) Exhibits


2.1	—	Agreement and Plan of Merger, dated August 30, 2005, among Layne Christensen Company, Layne Merger Sub 1, Inc., Reynolds, Inc. and the Stockholders of Reynolds, Inc. listed to the signature pages thereto (incorporated by reference to Exhibit 10.2 to Form 8-K of Layne Christensen Company filed October 4, 2005).

4.1	—	Amended and Restated Loan Agreement, dated as of September 28, 2005, by and among Layne Christensen Company, LaSalle Bank National Association, as Administrative Agent and as Lender, and the other Lenders listed therein (incorporated by reference to Exhibit 4.1 to Form 8-K of Layne Christensen Company filed October 4, 2005).

4.2	—	Letter Amendment No. 2 to Master Shelf Agreement, dated as of September 28, 2005, by and among Layne Christensen Company, Prudential Investment Management, Inc., The Prudential Insurance Company of America, Pruco Life Insurance Company, Security Life of Denver Insurance Company and such other Purchasers of the Notes as may be named in the Master Shelf Agreement from time to time (incorporated by reference to Exhibit 4.2 to Form 8-K of Layne Christensen Company filed October 4, 2005).

10.1	—	Reynolds Division of Layne Christensen Company Cash Bonus Plan, dated September 28, 2005 (incorporated by reference to Exhibit 10.1 to Form 8-K of Layne Christensen Company filed October 4, 2005).


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.

b) Reports on Form 8-K

			Form 8-K filed on August 31, 2005, related to the Company’s second quarter earnings announcement and the entry into a definitive agreement to acquire Reynolds, Inc.

			Form 8-K filed on October 4, 2005, related to the closing of the Reynolds acquisition.

* * * * * * * * * *

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: December 9, 2005		/s/ A.B. Schmitt
		A.B. Schmitt, President and Chief Executive Officer

DATE: December 9, 2005		/s/ Jerry W. Fanska
		Jerry W. Fanska, Vice President Finance and Treasurer

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