Layne Christensen 10Q 2006 Q2 Quarterly report

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 July 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 incorporation or organization)		(I.R.S. Employer Identification No.)


1900 Shawnee Mission Parkway, Mission Woods, Kansas		66205

(Address of principal executive offices)		(Zip Code)

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

Not Applicable

(Former name, former address and former fiscal year, if changed since last report.)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ. Noo.

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yesþ Noo

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 12,853,187 shares of common stock, $.01 par value per share, outstanding on August 24, 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
EX-31.1 Certification 302 - CEO
EX-31.2 Certification 302 - CFO
EX-32.1 Certification 906 - CEO
EX-32.2 Certification 906 - CFO

PART I

ITEM 1. Financial Statements

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(in thousands)


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

Current assets:
Cash and cash equivalents	$	12,117		$	14,408
Customer receivables, less allowance of $5,042 and $4,106, respectively		74,861			54,280
Costs and estimated earnings in excess of billings on uncompleted contracts		19,813			17,143
Inventories		19,244			18,098
Deferred income taxes		11,499			11,664
Income taxes receivable		338			1,186
Other		4,811			4,704

Total current assets		142,683			121,483


Property and equipment:
Land		7,604			6,842
Buildings		14,310			14,342
Machinery and equipment		179,019			176,141
Gas transportation facilities and equipment		7,425			6,413
Oil and gas properties		24,231			20,573
Mineral interest in oil and gas properties		3,973			3,671

		236,562			227,982
Less — Accumulated depreciation and depletion		(141,964	)		(138,526	)

Net property and equipment		94,598			89,456


Other assets:
Investment in affiliates		22,195			20,558
Goodwill		8,025			8,025
Deferred income taxes		1,969			2,931
Other		3,568			2,927

Total other assets		35,757			34,441


	$	273,038		$	245,380

See Notes to Consolidated Financial Statements.

- Continued -

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS — (Continued)
(in thousands, except per share data)


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

Current liabilities:
Accounts payable	$	27,883		$	25,758
Accrued compensation		14,224			14,397
Accrued insurance expense		6,299			5,781
Other accrued expenses		9,112			9,930
Income taxes payable		4,420			3,476
Billings in excess of costs and estimated earnings on uncompleted contracts		7,456			7,686

Total current liabilities		69,394			67,028


Noncurrent and deferred liabilities:
Long-term debt		76,700			60,000
Accrued insurance expense		6,752			8,247
Other		5,361			4,945

Total noncurrent and deferred liabilities		88,813			73,192


Minority interest		503			463


Contingencies

Stockholders’ equity:
Preferred stock, par value $.01 per share, 5,000,000 shares authorized, none issued and outstanding		—			—
Common stock, par value $.01 per share, 30,000,000 shares authorized, 12,837,291 and 12,618,641 shares issued and outstanding, respectively		128			126
Capital in excess of par value		93,314			90,707
Retained earnings		30,491			23,212
Accumulated other comprehensive loss		(9,464	)		(9,067	)
Unearned compensation		(141	)		(281	)


Total stockholders’ equity		114,328			104,697


	$	273,038		$	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						Six Months
	Ended July 31,						Ended July 31,
	(unaudited)						(unaudited)
	2005			2004			2005			2004
Revenues	$	106,102		$	86,186		$	202,760		$	162,395
Cost of revenues (exclusive of depreciation shown below)		77,789			62,169			148,869			118,322

Gross profit		28,313			24,017			53,891			44,073
Selling, general and administrative expenses		15,472			14,471			32,362			28,396
Depreciation, depletion and amortization		4,015			3,338			8,028			6,523
Other income (expense):
Equity in earnings of affiliates		1,153			1,220			2,272			1,689
Interest		(1,106	)		(733	)		(2,076	)		(1,416	)
Other, net		13			805			533			1,149

Income from continuing operations before income taxes and minority interest		8,886			7,500			14,230			10,576
Income tax expense		4,335			3,751			6,902			5,289
Minority interest		(17	)		—			(40	)		—

Net income from continuing operations before discontinued operations		4,534			3,749			7,288			5,287
Loss from discontinued operations, net of income tax benefit of $1 and $1 for the three months ended July 31, 2005 and 2004, respectively, and $1 and $96 for the six months ended July 31, 2005 and 2004, respectively		(8	)		(96	)		(9	)		(162	)

Net income	$	4,526		$	3,653		$	7,279		$	5,125


Basic income (loss) per share:
Net income from continuing operations	$	0.36		$	0.30		$	0.58		$	0.42
Loss from discontinued operations, net of tax		—			(0.01	)		—			(0.01	)

Income per share	$	0.36		$	0.29		$	0.58		$	0.41


Diluted income (loss) per share:
Net income from continuing operations	$	0.35		$	0.29		$	0.56		$	0.41
Loss from discontinued operations, net of tax		—			(0.01	)		—			(0.01	)

Income per share	$	0.35		$	0.28		$	0.56		$	0.40

Weighted average shares outstanding		12,661,000			12,559,000			12,628,000			12,548,000
Dilutive stock options		370,000			345,000			326,000			328,000

		13,031,000			12,904,000			12,954,000			12,876,000

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW
(in thousands)


	Six Months
	Ended July 31,
	2005			2004
	(unaudited)
Cash flow used in operating activities:
Net income	$	7,279		$	5,125
Adjustments to reconcile net income to cash from operations:
Loss on discontinued operations, net of tax		9			162
Depreciation, depletion and amortization		8,028			6,523
Deferred income taxes		1,134			662
Equity in earnings of affiliates		(2,272	)		(1,689	)
Dividends received from affiliates		717			671
Minority interest		40			—
Gain from disposal of property and equipment		(479	)		(1,292	)
Changes in current assets and liabilities:
Increase in customer receivables		(20,868	)		(14,438	)
Increase in costs and estimated earnings in excess of billings on uncompleted contracts		(2,696	)		(1,249	)
Increase in inventories		(1,525	)		(1,042	)
(Increase) decrease in other current assets		(35	)		1,834
Increase in accounts payable and accrued expenses		4,394			6,502
Decrease in billings in excess of costs and estimated earnings on uncompleted contracts		(230	)		(717	)
Other, net		7			(185	)

Cash from (used in) continuing operations		(6,497	)		867
Cash from (used in) discontinued operations		23			(3,899	)

Cash used in operating activities		(6,474	)		(3,032	)

Cash flow used in investing activities:
Additions to property and equipment		(8,441	)		(8,636	)
Additions to gas transportation facilities and equipment		(1,012	)		(1,349	)
Additions to mineral interest in oil and gas properties		(302	)		(720	)
Additions to oil and gas properties		(3,614	)		(4,609	)
Proceeds from disposal of property and equipment		695			2,371
Proceeds from sale of business		—			300
Acquisition of oil and gas working interest		—			(1,000	)
Acquisition of businesses		(359	)		—
Investment in joint ventures		(56	)		(278	)

Cash used in investing activities		(13,089	)		(13,921	)

Cash flow from financing activities:
Net borrowings under revolving credit facility		16,700			4,100
Payments on promissory note		(720	)		(1,020	)
Issuance of common stock		1,525			216
Payments on notes receivable from management stockholders		—			28

Cash from financing activities		17,505			3,324

Effects of exchange rate changes on cash		(233	)		(679	)

Net decrease in cash and cash equivalents		(2,291	)		(14,308	)
Cash and cash equivalents at beginning of period		14,408			21,602

Cash and cash equivalents at end of period	$	12,117		$	7,294

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 cash flow hedge positions, 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.

Derivatives —The Company follows SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, which requires all 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 physical delivery of 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 4 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 six months ended July 31, 2005 and 2004.

Pro forma net income and earnings per share for the three and six months ended July 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						Six Months
	Ended July 31,						Ended July 31,
	2005			2004			2005			2004
Net income, as reported	$	4,526		$	3,653		$	7,279		$	5,125
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax		(8	)		(17	)		(122	)		(34	)

Pro forma net income	$	4,518		$	3,636		$	7,157		$	5,091


Income per share:
Basic — as reported	$	0.36		$	0.29		$	0.58		$	0.41

Basic — pro forma	$	0.36		$	0.29		$	0.57		$	0.41

Diluted — as reported	$	0.35		$	0.28		$	0.56		$	0.40

Diluted — pro forma	$	0.35		$	0.28		$	0.55		$	0.40

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


	Six Months Ended July 31,
	2005		2004
Income taxes	$	2,843	$	197
Interest		1,416		1,381

2. 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 six months ended July 31, 2005 and 2004 were as follows (in thousands):


	Three Months						Six Months
	Ended July 31,						Ended July 31,
	2005			2004			2005			2004
Revenues:
Canada	$	—		$	—		$	—		$	—
Toledo		—			—			—			—

Total	$	—		$	—		$	—		$	—


Loss from discontinued operations before income taxes:
Canada	$	(8	)	$	(64	)	$	(9	)	$	(216	)
Toledo		(1	)		(33	)		(1	)		(42	)

Total	$	(9	)	$	(97	)	$	(10	)	$	(258	)

3. 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 (“Previous Loan Facilities”). 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 signing of the Master Shelf Agreement, the Company closed on a bank revolving credit facility (“Credit Agreement”), which was subsequently amended on July 15, 2005. The maximum available under the amended Credit Agreement is $40,000,000, less any outstanding letter of credit commitments (which are subject to a $15,000,000 sublimit) and is used for working capital requirements and general corporate purposes. The Credit Agreement provides interest at variable rates equal to, at the Company’s option, a Eurodollar rate plus 1.25% to 2.25% (depending upon certain ratios) or an alternative reference rate as defined in the Credit Agreement. The Credit Agreement will be due and payable on July 31, 2007. On July 31, 2005, there were letters of credit of $10,471,000 and borrowings of $16,700,000 outstanding on the Credit Agreement resulting in available capacity of $12,829,000.

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, minimum

tangible net worth and minimum asset coverage. The Company was in compliance with its covenants as of July 31, 2005.

Debt outstanding as of July 31, 2005 and January 31, 2005 are as follows (in thousands):


	July 31,		January 31,
	2005		2005
Long-term debt:
Credit Agreement	$	16,700	$	—
Senior Notes		60,000		60,000

Total long-term debt	$	76,700	$	60,000

4. 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 July 31, 2005, the Company had committed to deliver 784,000 million British Thermal Units (“MMBtu”) of natural gas through March 2006. The prices on these contracts range from $5.60 to $9.56 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 July 31, 2005 and January 31, 2005 was $(112,000) 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 $6,000,000 and $0 as of July 31, 2005 and January 31, 2005, respectively, to hedge the risks associated with forecasted Australian dollar denominated costs in its African operations. The contracts held as of July 31, 2005 settle in various increments through January 2006. The fair value of the instruments of $110,000 at July 31, 2005 is recorded in other current assets and in accumulated other comprehensive income net of income taxes of $42,500. Aggregate gains of $0 and $40,000 on foreign currency hedging transactions were recognized for the six months ended July 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.

5. Other Comprehensive Income (Loss)

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


	Three Months						Six Months
	Ended July 31,						Ended July 31,
	2005			2004			2005			2004
Net income	$	4,526		$	3,653		$	7,279		$	5,125
Other comprehensive income (loss), net of taxes:
Foreign currency translation adjustments		(177	)		(859	)		(310	)		(2,136	)
Change in unrecognized pension liability		—			—			(154	)		—
Unrealized gain (loss) on foreign exchange contracts		67			(180	)		67			(796	)

Other comprehensive income	$	4,416		$	2,614		$	6,882		$	2,193

The components of accumulated other comprehensive loss for the six months ended July 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		(310	)		(154	)		67		(397	)

Balance, July 31, 2005	$	(7,475	)	$	(2,056	)	$	67	$	(9,464	)


							Unrealized			Accumulated
	Cumulative			Unrecognized			Gain (Loss)			Other
	Translation			Pension			on Exchange			Comprehensive
	Adjustment			Liability			Contracts			Loss
Balance, February 1, 2004	$	(8,701	)	$	(1,784	)	$	856		$	(9,629	)
Period change		(2,136	)		—			(796	)		(2,932	)

Balance, July 31, 2004	$	(10,837	)	$	(1,784	)	$	60		$	(12,561	)

6. 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 six months ended July 31, 2005 and 2004 includes the following components (in thousands):


	Three Months						Six Months
	Ended July 31,						Ended July 31,
	2005			2004			2005			2004
Service cost	$	18		$	17		$	36		$	34
Interest cost		109			110			218			220
Expected return on assets		(121	)		(113	)		(242	)		(226	)
Net amortization		67			48			134			96

Net periodic pension cost	$	73		$	62		$	146		$	124

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 six months ended July 31, 2005 and 2004 include the following components (in thousands):


	Three Months				Six Months
	Ended July 31,				Ended July 31,
	2005		2004		2005		2004
Service cost	$	30	$	25	$	60	$	50
Interest cost		19		18		38		36

Net periodic pension cost	$	49	$	43	$	98	$	86

7. 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.

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

Revenues and income from continuing operations pertaining to the Company’s operating segments are presented below. 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. Two small specialty service companies that were previously reported in the energy division have been reclassified as “Other” below. All periods presented have been reclassified to conform to the current presentation. Operating segment revenues and income from continuing operations are summarized as follows (in thousands):


	Three Months					Six Months
	Ended July 31,					Ended July 31,
	2005			2004		2005		2004
Revenues
Water resources	$	58,776		$	47,918	$	114,387	$	93,201
Mineral exploration		33,110			26,153		63,669		50,242
Geoconstruction		10,453			10,949		18,509		17,039
Energy		2,325			639		4,103		928
Other		1,438			527		2,092		985

Total revenues	$	106,102		$	86,186	$	202,760	$	162,395


Equity in earnings of affiliates
Mineral exploration	$	1,172		$	1,194	$	1,964	$	1,663
Geoconstruction		(19	)		26		308		26

Total equity in earnings of affiliates	$	1,153		$	1,220	$	2,272	$	1,689


	Three Months						Six Months
	Ended July 31,						Ended July 31,
	2005			2004			2005			2004
Income (loss) from continuing operations before taxes
Water resources	$	5,668		$	6,299		$	10,267		$	10,330
Mineral exploration		5,536			3,705			9,653			7,227
Geoconstruction		1,114			1,654			1,762			1,519
Energy		352			(519	)		417			(1,254	)
Other		186			518			196			235
Unallocated corporate expenses		(2,864	)		(3,424	)		(5,989	)		(6,065	)
Interest		(1,106	)		(733	)		(2,076	)		(1,416	)

Total income from continuing operations before taxes	$	8,886		$	7,500		$	14,230		$	10,576


Geographic Information:
Revenues
North America	$	83,611		$	66,152		$	158,776		$	125,060
Africa/Australia		19,796			17,133			38,922			33,383
Other foreign		2,695			2,901			5,062			3,952

Total revenues	$	106,102		$	86,186		$	202,760		$	162,395

8. 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. While the resolution of any of these matters may have an impact on the financial results for the period in which the matter is resolved, 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.

9. 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.

10. Subsequent Event

On August 30, 2005, the Company signed a definitive agreement to acquire 100% of the outstanding stock of Reynolds, Inc. (“Reynolds”), a privately held company and a major supplier of product and services to the water and wastewater industries. The acquisition of Reynolds is subject to regulatory approval and is expected to close in the third quarter of fiscal 2006. The purchase price will be $60,000,000 in cash and 2,222,222 shares of the Company’s common stock with certain additional amounts payable contingent on events at closing and future operating results.

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						Six Months						Period-to-Period
	Ended July 31,						Ended July 31,						Change
													Three			Six
	2005			2004			2005			2004			Months			Months
Revenues:
Water resources		55.4	%		55.6	%		56.4			57.4	%		22.7	%		22.7	%
Mineral exploration		31.2			30.3			31.4			30.9			26.6			26.7
Geoconstruction		9.9			12.7			9.1			10.5			(4.5	)		8.6
Energy		2.2			0.7			2.0			0.6			263.8			342.1
Other		1.3			0.7			1.1			0.6			172.9			112.4

Total net revenues		100.0	%		100.0	%		100.0	%		100.0	%		23.1			24.9

Cost of revenues		73.3			72.1			73.4			72.9			25.1			25.8

Gross profit		26.7			27.9			26.6			27.1			17.9			22.3
Selling, general and administrative expenses		14.6			16.8			16.0			17.5			6.9			14.0
Depreciation, depletion and amortization		3.8			3.9			4.0			4.0			20.3			23.1
Other income (expense):
Equity in earnings of affiliates		1.1			1.4			1.1			1.0			(5.5	)		34.5
Interest		(1.0	)		(0.8	)		(1.0	)		(0.8	)		50.9			46.6
Other, net		0.0			0.9			0.3			0.7			(98.4	)		(53.6	)

Income from continuing operations before income taxes and minority interest		8.4			8.7			7.0			6.5			18.5			34.5
Income tax expense		4.1			4.4			3.4			3.2			15.6			30.5
Minority interest		0.0			0.0			0.0			0.0			*			*

Net income from continuing operations before discontinued operations		4.3			4.3			3.6			3.3			20.9			37.8
Loss from discontinued operations, net of tax		0.0			(0.1	)		0.0			(0.1	)		*			*

Net income		4.3	%		4.2	%		3.6	%		3.2	%		23.9			42.0


*		Not meaningful.


	Three Months						Six Months
	Ended July 31,						Ended July 31,
	2005			2004			2005			2004
Revenues Water resources	$	58,776		$	47,918		$	114,387		$	93,201
Mineral exploration		33,110			26,153			63,669			50,242
Geoconstruction		10,453			10,949			18,509			17,039
Energy		2,325			639			4,103			928
Other		1,438			527			2,092			985

Total revenues	$	106,102		$	86,186		$	202,760		$	162,395

Equity in earnings of affiliates
Mineral exploration	$	1,172		$	1,194		$	1,964		$	1,663
Geoconstruction		(19	)		26			308			26

Total equity in earnings of affiliates	$	1,153		$	1,220		$	2,272		$	1,689

Income (loss) from continuing operations before taxes
Water resources	$	5,668		$	6,299		$	10,267		$	10,330
Mineral exploration		5,536			3,705			9,653			7,227
Geoconstruction		1,114			1,654			1,762			1,519
Energy		352			(519	)		417			(1,254	)
Other		186			518			196			235
Unallocated corporate expenses		(2,864	)		(3,424	)		(5,989	)		(6,065	)
Interest		(1,106	)		(733	)		(2,076	)		(1,416	)

Total income from continuing operations before taxes	$	8,886		$	7,500		$	14,230		$	10,576

Results of Operations

Revenues for the three months ended July 31, 2005 increased $19,916,000, or 23.1%, to $106,102,000 while revenues for the six months ended July 31, 2004 increased $40,365,000, or 24.9%, to $202,760,000 from the same periods last year. See further discussion of results of operations by division below.

Gross profit as a percentage of revenues was 26.7% and 26.6% for the three and six months ended July 31, 2005 compared to 27.9% and 27.1% for the three and six months ended July 31, 2004. The decreases in gross profit percentage were primarily the result of reduced margins in the water resources division arising from higher than expected costs on certain water supply contracts. These decreases were partially offset by increased margins in the energy division due to the increased production and sales of natural gas.

Selling, general and administrative expenses increased to $15,472,000 and $32,362,000 for the three and six months ended July 31, 2005, compared to $14,471,000 and $28,396,000 for the three and six months ended July 31, 2004. The increase for both the three and six month periods was primarily related to the acquisition of 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 in the current periods.

Depreciation, depletion and amortization increased to $4,015,000 and $8,028,000 for the three and six months ended July 31, 2005, compared to $3,338,000 and $6,523,000 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 Beylik acquisition and increased depletion expense resulting from the increase in production of natural gas from the Company’s coalbed methane operations.

Equity in earnings of affiliates for the three months ended July 31, 2005 was consistent with the prior year and for the six months ended July 31, 2005 increased $583,000 to $2,272,000, compared to $1,689,000 for the same period in the prior year. The increase was 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 $1,106,000 and $2,076,000 for the three and six months ended July 31, 2005, compared to $733,000 and $1,416,000 for same periods last year. The increase was a result of an increase in the Company’s average borrowings during the year.

Other, net was $13,000 and $533,000 for the three and six months ended July 31, 2005, compared to $805,000 and $1,149,000 for the three and six months ended July 31, 2004. The decreases in both periods were primarily due to reduced gains on sales of non-strategic assets.

The Company’s effective tax rate was 48.8% and 48.5% for the three and six months ended July 31, 2005, compared to 50.0% for both the three and six months ended July 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				Six months ended
	July 31,				July 31,
	2005		2004		2005		2004
Revenues	$	58,776	$	47,918	$	114,387	$	93,201
Income from continuing operations before income taxes		5,668		6,299		10,267		10,330

Water resources revenues increased 22.7% for both the three and six months ended July 31, 2005, compared to the same periods in the prior year. The increases were primarily attributable to the Company’s continued efforts to increase market share, additional capacity from the Beylik acquisition and the results from the Company’s water treatment initiatives.

Income from continuing operations for the water resources division decreased 10.0% to $5,668,000 for the three months ended July 31, 2005, and 0.6% to $10,267,000 for the six months ended July 31, 2005, compared to $6,299,000 and $10,330,000 for the three and six months ended July 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 technology to the division’s water treatment initiatives. Additionally, the second quarter of the prior year included a non-recurring gain on sale of property and equipment of $250,000.

Mineral Exploration Division
(in thousands)


	Three months ended				Six months ended
	July 31				July 31,
	2005		2004		2005		2004
Revenues	$	33,110	$	26,153	$	63,669	$	50,242
Income from continuing operations before income taxes		5,536		3,705		9,653		7,227

Mineral exploration revenues increased 26.6% to $33,110,000 and 26.7% to $63,669,000 for the three and six months ended July 31, 2005, compared to revenues of $26,153,000 and $50,242,000 for the three and six months ended July 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 $5,536,000 for the three months ended July 31, 2005 and $9,653,000 for the six months ended July 31, 2005, compared to $3,705,000 and $7,227,000 for the three and six months ended July 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, partially offset by increased accrued incentive compensation expense due to improved profitability in the current year.

Geoconstruction Division
(in thousands)


	Three months ended				Six months ended
	July 31				July 31,
	2005		2004		2005		2004
Revenues	$	10,453	$	10,949	$	18,509	$	17,039
Income from continuing operations before income taxes		1,114		1,654		1,762		1,519

Geoconstruction revenues decreased 4.5% to $10,453,000 for the three months ended July 31, 2005 and increased 8.6% to $18,509,000 for the six months ended July 31, 2005, compared to $10,949,000 and $17,039,000 for the three and six months ended July 31, 2004. The decrease in revenue for the second quarter was primarily the result of the timing of work performed on certain significant projects. The increase for the six month period was primarily the result of a significant increase in jet grouting work in the northeast and increased product sales by the Company’s manufacturing unit in Italy.

Income from continuing operations for the geoconstruction division was $1,114,000 for the three months ended July 31, 2005 and $1,762,000 for the six months ended July 31, 2005, compared to $1,654,000 and $1,519,000 for the three and six months ended July 31, 2004. The decrease in income from continuing operations for the three months ended July 31, 2005 was primarily associated with favorable gross profit margins on certain significant projects in the prior year. The increase in income from continuing operations for the six month period was primarily due to incremental earnings from the division’s joint venture.

Energy Division
(in thousands)


	Three months ended					Six months ended
	July 31					July 31,
	2005		2004			2005		2004
Revenues	$	2,325	$	639		$	4,103	$	928
Income (loss) from continuing operations before income taxes		352		(519	)		417		(1,254	)

Energy division revenues increased $1,686,000 to $2,325,000, or 263.8%, and $3,175,000 to $4,103,000, or 342.1%, for the three and six months ended July 31, 2005, compared to revenues of $639,000 and $928,000 for the three and six months ended July 31, 2004. The increase in revenues was primarily attributable to increased production of natural gas from the Company’s coalbed methane properties.

Income from continuing operations increased $871,000 to $352,000 and $1,671,000 to $417,000 for the three and six months ended July 31, 2005, compared to losses of $519,000 and $1,254,000 for the same periods last year. The increases in income were due to the increase in production of natural gas and certain overhead cost reductions.

Unallocated Corporate Expenses

Unallocated corporate expenses decreased to $2,864,000 and $5,989,000 for the three and six months ended July 31, 2005, compared to $3,424,000 and $6,065,000 for the three and six months ended July 31, 2004. The decrease for the three month period was primarily due to charges in the prior year related to the write-down of non-strategic assets of $300,000.

Changes in Financial Condition

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

The Company maintains an agreement (the “Master Shelf Agreement”) whereby it has issued $60,000,000 in unsecured notes. The Company also holds a revolving credit facility (the “Credit Agreement”) composed of an unsecured $40,000,000 revolving facility. At July 31, 2005, the Company had $16,700,000 outstanding under the Credit Agreement and outstanding notes of $60,000,000 under the Master Shelf Agreement (see Note 3 of the Notes to Consolidated Financial Statements). On July 15, 2005, the Company amended the Credit Agreement which increased the Company’s revolving loan commitment from $30,000,000 to $40,000,000, reduced the interest rates payable by the Company on its borrowings under the revolving loan and extended the maturity date of the revolving loan to July 31, 2007. The Company was in compliance with its financial covenants at July 31, 2005 and expects to remain in compliance through the foreseeable future.

The Company’s working capital as of July 31, 2005 and January 31, 2005 was $73,289,000 and $54,455,000, respectively. The increase in working capital at July 31, 2005 was primarily attributable to the increase in the balance of accounts receivable as a result of the growth in revenues. 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 2006.

Operating Activities

Cash used in operating activities, excluding discontinued operations, was $6,497,000 for the six months ended July 31, 2005, compared to cash provided from operations of $867,000 for the six months ended July 31, 2004. 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 six months ended July 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

The Company’s capital expenditures of $13,369,000 for the six months ended July 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 six months ended July 31, 2005, the Company borrowed $16,700,000 under its credit facilities primarily for working capital requirements and to fund capital expenditures. Additionally, proceeds 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		1 year		1-3 years		4-5 years		5 years
Contractual Obligations and Other Commercial Commitments
Credit facilities	$	76,700	$	—	$	30,033	$	40,000	$	6,667
Operating leases		20,015		8,400		10,104		1,511		—
Mineral interest obligations		402		89		221		70		22
Promissory note		720		720		—		—		—

Total contractual cash obligations		97,837		9,209		40,358		41,581		6,689

Standby letters of credit		10,471		10,471		—		—		—
Asset retirement obligations		480		—		—		—		480

Total contractual obligations and commercial commitments	$	108,788	$	19,680	$	40,358	$	41,581	$	7,169

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 facilities do not include interest payments. The credit facilities bear fixed interest rates of 6.05% and 5.40% (see Note 3 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.

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.

of the last day of the quarter, with effect given to the Company’s cash flow hedge positions, 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 OtherContingencies — 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 3 of this Form 10-Q. As of July 31, 2005, $60,000,000 of the Company’s long-term debt outstanding carries a fixed-rate and $16,700,000 is variable rate debt. An instantaneous change in interest rates of one percentage point would not significantly impact the Company’s annual interest expense.

Operating in international markets involves exposure to possible volatile movements in currency exchange rates. Currently, the Company’s primary international operations are in Australia, Africa, Mexico and Italy. The operations are described in Note 1 of the Notes to Consolidated Financial Statements appearing in the Company’s January 31, 2005 Form 10-K and Note 7 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 4 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 six months ended July 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 July 31, 2005, the Company held contracts for physical delivery of 784,000 million British Thermal Units (“MMBtu”) of natural gas at prices ranging from $5.60 to $9.56 per MMBtu. The estimated fair value of such contracts at July 31, 2005 was $(112,000).

We estimate that a 10% change in the price of natural gas would impact income from continuing operations before taxes by approximately $232,000 for the six months ended July 31, 2005.

ITEM 4. Controls and Procedures

Based on an evaluation of disclosure controls and procedures for the period ended July 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 July 31, 2005, the Company concluded that its internal control over financial reporting is effective as of July 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.

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

An annual meeting of stockholders was held on June 9, 2005. Set forth below is a brief description of each matter voted upon at the meeting and the results of the balloting:

Election of Donald K. Miller as a Class I Director to hold office for a term expiring at the 2008 Annual Meeting of the Stockholders of the Company and until his successor is duly elected and qualified or until his earlier death, retirement, resignation or removal:


For	Against	Withheld Authority
10,938,108	0	1,175,902

Election of Andrew B. Schmitt as a Class I Director to hold office for a term expiring at the 2008 Annual Meeting of the Stockholders of the Company and until his successor is duly elected and qualified or until his earlier death, retirement, resignation or removal:


For	Against	Withheld Authority
11,179,164	0	934,846

Election of Anthony B. Helfet as a Class I Director to hold office for a term expiring at the 2008 Annual Meeting of the Stockholders of the Company and until his successor is duly elected and qualified or until his earlier death, retirement, resignation or removal:


For	Against	Withheld Authority
11,431,979	0	682,031

Approval of a stockholder proposal to declassify the Company’s Board of Directors:


For	Against	Withheld Authority
9,653,881	890,299	13,082

ITEM 5 — Other Information

NONE

ITEM 6 — Exhibits and Reports on Form 8-K

Exhibits


31(1)	—	Section 302 Certification of Chief Executive Officer of the Company

31(2)	—	Section 302 Certification of Chief Financial Officer of the Company

32(1)	—	Section 906 Certification of Chief Executive Officer of the Company

32(2)	—	Section 906 Certification of Chief Financial Officer of the Company

	b)		Reports on Form 8-K

			Form 8-K filed on May 6, 2005 related to a letter agreement amending Andrew B. Schmitt’s existing supplemental retirement benefit.

			Form 8-K filed June 1, 2005 related to the Company’s first quarter press release.

			Form 8-K filed June 15, 2005 announcing changes to the Company’s Board of Directors.

			Form 8-K filed June 29, 2005 announcing a signed Letter of Intent for the Company to purchase Reynolds, Inc.

			Form 8-K filed July 21, 2005 regarding an amendment to the Company’s loan agreement.

* * * * * * * * * *

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: September 2, 2005		/s/ A.B. Schmitt

		A.B. Schmitt, President
		and Chief Executive Officer

DATE: September 2, 2005		/s/Jerry W. Fanska

		Jerry W. Fanska, Vice President
		Finance and Treasurer

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Bad

Layne Christensen (LAYN) Inactive 10-Q2006 Q2 Quarterly report

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