Exhibit 99.1
[Wiser Oil Logo]
8115 Preston Road, Suite 400, Dallas, Texas 75225
Phone: 214/265-0080 Fax: 214/373-3610
http://www.wiseroil.com
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For Immediate Release
Contact:
Rick Davis, VP Finance
Phone: (214) 265-0080
Email: rdavis@wiseroil.com
The Wiser Oil Company Reports Fourth Quarter Results
and Year-end Reserves;
Cash Flow and EBITDAX Up Sharply
Dallas, Texas, February 24, 2004 —The Wiser Oil Company (NYSE: WZR) today reported financial and operating results for the fourth quarter and year ended December 31, 2003:
| Three Months Ended | Year Ended | |||||||||||
| 12/31/03 | 12/31/02 | 12/31/03 | 12/31/02 | |||||||||
Average Daily Production – MCFE | 60,250 | 66,793 | 64,005 | 65,211 | ||||||||
Average MCFE Price Received* | $ | 4.26 | $ | 3.60 | $ | 4.59 | $ | 3.19 | ||||
Average Daily Gas Production – MCF | 32,337 | 36,989 | 35,123 | 34,110 | ||||||||
Average Gas Price Received* | $ | 4.26 | $ | 3.31 | $ | 4.72 | $ | 2.64 | ||||
Average Daily Oil Production – BBLS | 4,326 | 4,761 | 4,482 | 4,962 | ||||||||
Average Oil Price Received* | $ | 26.02 | $ | 23.62 | $ | 27.19 | $ | 22.92 | ||||
Total Oil & Gas Revenues – 000’s | $ | 23,604 | $ | 22,126 | $ | 107,346 | $ | 76,775 | ||||
Discretionary Cash Flow (note 1) – 000’s | $ | 7,725 | $ | 2,965 | $ | 39,280 | $ | 14,773 | ||||
EBITDAX (note 2) – 000’s | $ | 13,899 | $ | 8,000 | $ | 56,139 | $ | 30,686 | ||||
* - excluding effects of hedging.
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Fourth Quarter 2003 Financial Results
Oil and gas revenues for the fourth quarter 2003 were $23.6 million, up 7% or $1.5 million from fourth quarter 2002 due to higher realized oil and gas prices. Realized oil prices for the quarter averaged $26.02 per barrel, up $2.40 from fourth quarter 2002, and realized gas prices for the quarter averaged $4.26 per MCF, up $0.95 from fourth quarter 2002.
During the fourth quarter of 2003, Wiser produced approximately 3.0 BCF of gas and 428,000 barrels of oil and NGL’s for a total of 5.5 BCFE, down 9.8% from fourth quarter 2002 production of 6.1 BCFE and down 5% from third quarter 2003 production of 5.8 BCFE. Oil production for the fourth quarter was down 9% due to the Provost sale in Canada in 2002 and normal decline from mature fields in the U.S and Canada. In addition, approximately 200 BOPD of oil production was shut-in during the fourth quarter of 2003 at our Hayter property in Canada due to temporary third-party facility constraints. The constraints were removed with the addition of new Company-owned facilities in January 2004. Gas production for the fourth quarter of 2003 was down 12.6% from 2002 primarily at the Wolverine and Wild River fields in Canada. New gas production commenced in mid-December 2003 from West Cameron Block 488 in the Gulf of Mexico and, in Canada, the Wild River 15-30 well started production in early January 2004.
In October 2003, the Company sold several small non-operated properties in Canada for $3.1 million and recognized a gain of $2.7 million.
Operating costs in the fourth quarter of 2003 were down 3% from fourth quarter 2002, however per MCFE costs were up 8% from fourth quarter 2002 to $1.34. Operating costs for the fourth quarter of 2003 were adversely affected by the Canadian dollar exchange rate which increased our Canadian operating costs by $0.6 million over fourth quarter 2002 levels. Had the 2003 Canadian dollar exchange rate been flat with 2002, per unit operating costs would have declined by 1%. The Company began selling CO2 from the Wellman unit in May 2003, which reduced fourth quarter 2003 operating costs by $0.7 million (CO2 sales are credited against operating costs). Depreciation, depletion and amortization (“DD&A”) for the fourth quarter of 2003 was $2.17 per MCFE, up 62% per MCFE from fourth quarter 2002 due to higher per unit rates at the Wolverine field in Canada and several other properties that were impaired at year-end 2003 as discussed below. As a result of the higher DD&A and impairment expense recognized in the fourth quarter of 2003, the DD&A rate for 2004 is expected to be in the range of $1.35 to $1.40 per MCFE.
The Company recognized $24.8 million of impairment expense for proved properties, consisting primarily of $22.3 million for the Wolverine field in Canada ($16.5 million net of deferred taxes). The impairment was the result of reclassifying certain proved undeveloped reserves to probable status and the removal of additional reserves due to poor performance of prior-year drilling programs.
Net loss for the fourth quarter of 2003 was $26.8 million, or ($1.73) per basic and diluted share, compared to a net loss of $13.1 million for the fourth quarter of 2002. Impairment expense was the largest contributing factor to the fourth quarter 2003 loss. Discretionary cash flow (see note 1 below) for the fourth quarter of 2003 was $7.7 million ($0.49 per diluted share), up $4.7 million from fourth quarter 2002 discretionary cash flow of $3.0 million and down $2.8 million from third quarter 2003 discretionary cash flow of $10.5 million.
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EBITDAX (see note 2 below) for the fourth quarter of 2003 was $13.9 million, up $5.9 million from fourth quarter 2002 EBITDAX of $8.0 million and down slightly from third quarter 2003 EBITDAX of $14.0 million. Capital and exploration expenditures for the fourth quarter of 2003 were $12.3 million, with $6.2 million of expenditures in Canada and $6.1 million in the U.S.
Year 2003 Financial Results
Oil and gas revenues for 2003 were $107.3 million, up 40% or $30.6 million from 2002 due to higher gas production and higher realized oil and gas prices. Realized oil prices for 2003 averaged $27.19 per barrel, up 18% from 2002. Realized gas prices for 2003 averaged $4.72 per MCF, up 75% from 2002. Average prices received by the Company in 2003 were approximately $3.85 per barrel less than the average NYMEX oil price and $0.72 per MCF lower than the average NYMEX gas price.
Wiser produced 12.8 BCF of gas and 1,757,000 barrels of oil and NGL’s in 2003 for a total of 23.4 BCFE, down 1.8% from 2002 production of 23.8 BCFE. Gas production for 2003 increased to 55% of total BCFE production compared to 52% in 2002 as the Company continues to focus on increasing gas production. Gulf of Mexico gas production for 2003 was up 2.0 BCF over 2002 and comprised 21% of total 2003 gas production compared to 6% of total gas production in 2002. Gas production at Wolverine for 2003 declined by 0.7 BCF from 2002 and South Texas gas production declined by 0.5 BCF from 2002.
Operating costs per MCFE for 2003 were essentially even with 2002 despite the adverse impact of the Canadian dollar exchange rate, which increased our Canadian operating costs by $1.4 million or $0.06 per MCFE. Offsetting this increase, CO2 sales at Wellman reduced our 2003 operating costs by $1.9 million. DD&A for 2003 was $1.63 per MCFE, up 28% per MCFE from 2002 due to higher per unit rates at the Wolverine field in Canada and in the Gulf of Mexico. The DD&A rate for 2004 is projected to be in the range of $1.35 to $1.40 per MCFE due primarily to the impairment expense recognized in the fourth quarter of 2003.
Net loss for 2003 was $23.6 million, or ($1.81) per common and diluted share, compared to a net loss of $52.2 million for 2002. The net loss for 2003 was $4.7 million excluding $18.9 million of impairment expense, net of tax. Discretionary cash flow for 2003 was $39.3 million ($2.52 per diluted share), up $24.5 million from 2002 discretionary cash flow of $14.8 million. Net loss includes a $5.2 million after-tax gain on the cumulative effect of accounting change for the adoption of Statement of Financial Accounting Standards No. 143 for asset retirement obligations. In addition, the higher Canadian dollar exchange rate increased accumulated other comprehensive income in stockholder’s equity by $14.3 million.
EBITDAX for 2003 was $56.1 million up $25.4 million, or 83%, from $30.7 million in 2002.
Capital and exploration expenditures for 2003 were $47.6 million, with $26.5 million of expenditures in Canada and $21.1 million in the U.S. During 2003, the Company spent $7.8 million on unproved land and seismic related costs to increase its inventory of exploration projects in both the U.S. and Canada.
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Wiser received $4.0 million in proceeds from several small property sales in Canada during 2003 and repaid $1.6 million under its revolving credit facility. However, due to an increase in the Canadian dollar exchange rate, long-term debt increased $1.7 million during 2003 to $154.2 million at December 31, 2003. The Company’s cash balance at December 31, 2003 was $1.4 million.
Year-End 2003 Reserves
The Company’s total proved oil and gas reserves as of December 31, 2003, as prepared by the Company’s independent petroleum consultants, DeGolyer and MacNaughton (“D&M”) and Gilbert, Lausten and Jung (“GLJ”) were 191.2 BCFE The reserves were comprised of 97.4 BCF of natural gas and 15.6 million barrels of oil and natural gas liquids.
Natural gas reserves accounted for 51% of total proved reserves at year-end 2003 as compared to 52% at year-end 2002. The Company’s reserve life index at year-end 2003 was 8.2 years with 85% of total proved reserves classified as proved developed.
Using SEC guidelines, Wiser’s total proved reserves at December 31, 2003 had a net present value (discounted at 10 percent) before federal income taxes, of $350 million. Approximately 91% of the present value was attributable to proved developed reserves.
During 2003, the Company replaced 90% of its 2003 production, not including the effect of property sales and negative revisions. A total of 21 BCFE was added to the Company’s reserve base during 2003 through new discoveries and extensions at a finding cost of $1.90 per MCFE excluding land and seismic related costs. The “all-in” cost was $2.27 per MCFE. The following is a reconciliation of proved reserve quantities using SEC guidelines as of December 31, 2002 and December 31, 2003:
| BCF Natural Gas | MMBBL Liquids | BCFE Total | |||||||
December 31, 2002 | 109.020 | 16.715 | 209.313 | ||||||
Discoveries and Extensions | 15.429 | 0.925 | 20.978 | ||||||
Purchases | 0.000 | 0.000 | 0.000 | ||||||
Production | (12.820 | ) | (1.757 | ) | (23.362 | ) | |||
Revisions | (13.131 | ) | (0.200 | ) | (14.331 | ) | |||
Sales | (1.107 | ) | (0.043 | ) | (1.367 | ) | |||
December 31, 2003 | 97.391 | 15.640 | 191.231 | ||||||
Material discoveries were made in 2003 in the Gulf of Mexico and at the Company’s Wild River 15-30 well in Canada. The 15-30 well went on line in early January and is producing at a gross rate of approximately 20 MMCFE per day (50% working interest). A series of previously reported Gulf of Mexico discoveries will go on line in the second quarter of 2004 in time to contribute significant production and cash flow to the Company this year.
Meaningful reserve extensions were made in 2003 at the Hayter property in Canada and in the San Juan Basin area of northwest New Mexico as a result of ongoing development activity. Due
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to the unique nature of the Company’s San Juan property (large number of wells, low average working interest and size of the capital spending program) all reserve changes were considered to be extensions. Additional reserve extensions are expected in future years at both of these properties.
The bulk of negative revisions occurred in the Company’s Canadian reserve base. These revisions were due in part to more conservative engineering guidelines associated with new Canadian securities regulations.
The Company has additional non-proved reserves at the Wellman Unit CO2 project in West Texas. These hydrocarbon reserves, along with the CO2 reserves, are considered to be part of a separate non-hydrocarbon business and, therefore, can not be included in the Company’s SEC reserve estimate.
The project, also engineered by D&M, contains recoverable reserves of 207 MBBLS of natural gas liquids and 35.8 BCF of CO2. The pre-tax net present value (discounted at 10 percent) of the project is $11.6 million. Adding these figures to the SEC calculation results in a total pre-tax present value for the Company (discounted at 10 percent) at December 31, 2003 of $361.6 million.
Updated Guidance for 2004
The Company estimates its first quarter 2004 production will be approximately 6.0 BCFE and reiterates its total 2004 production estimate of approximately 25.5 to 26.5 BCFE. First quarter 2004 discretionary cash flow is projected to be approximately $10.0 to $10.5 million and EBITDAX is projected to be approximately $13.7 to $14.2 million.
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Note 1
Discretionary cash flow is defined as cash flows from operating activities before changes in operating assets and liabilities and exploration expense. Management believes that discretionary cash flow is a better liquidity measure for oil and gas companies because; (a) exploration expense is a discretionary component of the Company’s capital budget that effects cash flows from operating activities and; (b) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the Company may not control and may not relate to the period that the operating activities occurred. Discretionary cash flow should not be considered in isolation or as a substitute for cash flows from operating activities prepared in accordance with generally accepted accounting principles. Discretionary cash flow as defined above may not be comparable to similarly titled measures of other companies. Following is a reconciliation of discretionary cash flow to cash flows from operating activities:
| Fourth Quarter |
Year | ||||||||||||||
| 2003 | 2002 | 2003 | 2002 | ||||||||||||
Cash flows from operating activities | $ | 9,033 | $ | 489 | $ | 34,903 | $ | 13,213 | |||||||
Add back exploration expense* | 1,097 | 1,584 | 8,607 | 8,719 | |||||||||||
Add back (deduct) net changes in operating assets and liabilities | (2,405 | ) | 892 | (4,230 | ) | (7,159 | ) | ||||||||
Discretionary Cash Flow | $ | 7,725 | $ | 2,965 | $ | 39,280 | $ | 14,773 | |||||||
| * | Excluding impairments and abandonments. |
Note 2
EBITDAX is defined as net income before interest, income taxes, DD&A, impairments, exploration expense, non-cash gains, and non-cash gain or loss on derivative value. Wiser has included information concerning EBITDAX because it is used by management and certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry. EBITDAX should not be considered in isolation or as a substitute for net income, cash flow from operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the Company’s profitability or liquidity. EBITDAX as defined above may not be comparable to similarly titled measures of other companies. Following is a reconciliation of EBITDAX to net income:
| Fourth Quarter | Year | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Net income (loss) before dividends and accounting change | $ | (26,818 | ) | $ | (11,283 | ) | $ | (25,645 | ) | $ | (45,397 | ) | ||||
Add back interest expense | 3,611 | 3,665 | 14,517 | 14,328 | ||||||||||||
Deduct income tax benefit | (6,998 | ) | (1,001 | ) | (8,239 | ) | (4,658 | ) | ||||||||
Add back DD&A & impairment | 36,756 | 8,670 | 62,804 | 40,172 | ||||||||||||
Add back exploration expense | 3,301 | 9,636 | 13,449 | 21,317 | ||||||||||||
Add back non-cash gain (loss) on derivative value | 4,047 | (1,687 | ) | (747 | ) | 4,924 | ||||||||||
EBITDAX | $ | 13,899 | $ | 8,000 | $ | 56,139 | $ | 30,686 | ||||||||
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Conference Call
The public is invited to listen to the Company’s conference call set for February 25, 2004 at 10:00 a.m. CT. The call is available via web cast by accessingwww.wiseroil.com or you may call in via telephone; 1-800-289-0468 (U.S. and Canada) or 1-913-981-5517 (International) and reference confirmation code 583878. If you are unable to participate during the live web cast, the call will be available on our web site for approximately 30 days.
Annual Meeting
The Company today announced its 2004 Annual Meeting of the Shareholders will be held on Monday, June 7th at 3:00 p.m. CT at the Hilton Park Cities Hotel located at 5954 Luther Lane, Dallas, Texas. The record date for determination of shareholders entitled to vote at the annual meeting will be the close of business on April 23, 2004.
Glossary of terms
BCF – billion cubic feet.
BOE – barrels of oil equivalent.
BOEPD – barrels of oil equivalent per day.
BOPD – barrels of oil per day
MBBL – thousand barrels
MMBBL – million barrels of oil
MCF – thousand cubic feet
MCFE – thousand cubic feet of gas equivalent
MMBTU – million British thermal units.
MMCFPD – million cubic feet of gas per day.
MMCFE – million cubic feet of gas equivalent.
WI – working interest.
Except for historical information contained herein, the statements in this Press Release are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements, and the business prospects of The Wiser Oil Company, are subject to a number of risks and uncertainties which may cause the Company’s actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of oil and gas prices, product supply and demand, competition, government regulation or action, litigation, the costs and results of drilling and operations, the Company’s ability to replace reserves or implement its business plans, access to and cost of capital, uncertainties about estimates of reserves, quality of technical data, and environmental risks. These and other risks are described in the Company’s Form 10-K and Form 10-Q Reports and other filings with the Securities and Exchange Commission.
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THE WISER OIL COMPANY
(and Consolidated Subsidiaries)
(UNAUDITED) Quarter Ended Dec. 31, | (UNAUDITED) Year Ended Dec. 31, | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Total production (MMCFE) | 5,543 | 6,145 | 23,362 | 23,802 | ||||||||||||
Oil (MBBL) | 398 | 438 | 1,636 | 1,811 | ||||||||||||
Gas (MMCF) | 2,975 | 3,403 | 12,820 | 12,450 | ||||||||||||
Natural gas liquids (MBBL) | 30 | 19 | 121 | 81 | ||||||||||||
Average oil price/BBL | $ | 26.02 | $ | 23.62 | $ | 27.19 | $ | 23.07 | ||||||||
Average gas price/MCF | 4.26 | 3.31 | 4.72 | 2.69 | ||||||||||||
Average natural gas liquids price/BBL | 19.23 | 26.51 | 19.67 | 19.11 | ||||||||||||
Condensed Consolidated Statement of Operations | ||||||||||||||||
(In thousands, except per share data) | ||||||||||||||||
Revenues | ||||||||||||||||
Oil and condensate | $ | 10,339 | $ | 10,341 | $ | 44,472 | $ | 41,781 | ||||||||
Natural gas | 12,680 | 11,277 | 60,486 | 33,452 | ||||||||||||
Natural gas liquids | 585 | 508 | 2,388 | 1,542 | ||||||||||||
Gain on sale of property | 2,742 | 1,549 | 3,056 | 2,296 | ||||||||||||
Interest and other income | (84 | ) | 127 | 17 | 416 | |||||||||||
Total revenues | 26,262 | 23,802 | 110,419 | 79,487 | ||||||||||||
Expenses | ||||||||||||||||
Operating costs | 7,417 | 7,650 | 26,673 | 26,931 | ||||||||||||
Production taxes | 843 | 795 | 3,882 | 3,092 | ||||||||||||
Depreciation, depletion and amortization | 12,006 | 8,255 | 38,054 | 30,257 | ||||||||||||
Property impairment | 24,750 | 415 | 24,750 | 9,915 | ||||||||||||
Loss on derivatives | 5,202 | 2,880 | 12,543 | 14,144 | ||||||||||||
Exploration | 3,301 | 9,636 | 13,449 | 21,317 | ||||||||||||
General and administrative | 2,948 | 2,790 | 10,435 | 9,558 | ||||||||||||
Interest expense | 3,611 | 3,665 | 14,517 | 14,328 | ||||||||||||
Total expenses | 60,078 | 36,086 | 144,303 | 129,542 | ||||||||||||
Income (loss) before income taxes and cumulative | (33,816 | ) | (12,284 | ) | (33,884 | ) | (50,055 | ) | ||||||||
Income Tax Expense (Benefit)—Deferred | (6,998 | ) | (1,001 | ) | (8,239 | ) | (4,658 | ) | ||||||||
Net income (loss) before cumulative effect of accounting change | (26,818 | ) | (11,283 | ) | (25,645 | ) | (45,397 | ) | ||||||||
Cumulative effect of accounting change, net of tax | — | — | 5,238 | — | ||||||||||||
Net income (loss) before dividends and amortization | (26,818 | ) | (11,283 | ) | (20,407 | ) | (45,397 | ) | ||||||||
Preferred dividends | — | (441 | ) | (700 | ) | (1,750 | ) | |||||||||
Preferred stock discount amortization | — | (1,390 | ) | (2,530 | ) | (5,066 | ) | |||||||||
Net Income (Loss)—Common Stock | $ | (26,818 | ) | $ | (13,114 | ) | $ | (23,637 | ) | $ | (52,213 | ) | ||||
SHARE INFORMATION | ||||||||||||||||
Common shares outstanding | 15,470 | 9,402 | 13,078 | 9,333 | ||||||||||||
Common shares outstanding—diluted | 15,821 | 15,284 | 15,599 | 15,217 | ||||||||||||
Basic Earnings (Loss) Per Share | $ | (1.73 | ) | $ | (1.39 | ) | $ | (1.81 | ) | $ | (5.59 | ) | ||||
Diluted Earnings (Loss) Per Share | $ | (1.73 | ) | $ | (1.39 | ) | $ | (1.81 | ) | $ | (5.59 | ) | ||||
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THE WISER OIL COMPANY
(and Consolidated Subsidiaries)
| CONDENSED CONSOLIDATED BALANCE SHEETS | (UNAUDITED) | |||||
| (In thousands) | Dec. 31, 2003 | Dec. 31, 2002 | ||||
Assets | ||||||
Current assets | $ | 16,404 | $ | 16,490 | ||
Property, net | 206,161 | 203,213 | ||||
Other assets | 2,031 | 2,504 | ||||
| $ | 224,596 | $ | 222,207 | |||
Liabilities and Stockholders’ Equity | ||||||
Current liabilities | $ | 30,030 | $ | 23,498 | ||
Other long-term liabilities | 9,574 | 3,299 | ||||
Long-term debt | 154,196 | 152,516 | ||||
Deferred taxes | — | 6,603 | ||||
Stockholders’ equity | 30,796 | 36,291 | ||||
| $ | 224,596 | $ | 222,207 | |||
| CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||||
| (In thousands) | ||||||||||||||||
| (UNAUDITED) | (UNAUDITED) | |||||||||||||||
| Quarter Ended Dec. 31, | Year Ended Dec. 31, | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Net income (loss) before pfd. dividends & amortization | $ | (26,818 | ) | $ | (11,283 | ) | $ | (20,407 | ) | $ | (45,397 | ) | ||||
DD&A | 12,006 | 8,255 | 38,054 | 30,257 | ||||||||||||
Property impairments and abandonments | 26,954 | 8,467 | 29,592 | 22,513 | ||||||||||||
Deferred income tax benefit | (6,998 | ) | (1,001 | ) | (8,239 | ) | (4,658 | ) | ||||||||
Cumulative effect of accounting change | — | — | (5,238 | ) | — | |||||||||||
Property sale gains | (2,742 | ) | (1,549 | ) | (3,056 | ) | (2,296 | ) | ||||||||
Non-cash loss on derivative value | 4,047 | (1,687 | ) | (747 | ) | 4,924 | ||||||||||
Other non-cash charges | 179 | 179 | 714 | 711 | ||||||||||||
Changes in operating assets and liabilities, net | 2,405 | (892 | ) | 4,230 | 7,159 | |||||||||||
Cash flow from operating activities | 9,033 | 489 | 34,903 | 13,213 | ||||||||||||
Capital expenditures | (11,218 | ) | (5,012 | ) | (38,975 | ) | (38,539 | ) | ||||||||
Proceeds from property sales | 3,078 | 6,083 | 3,959 | 8,342 | ||||||||||||
Preferred cash dividends | — | (442 | ) | (921 | ) | (879 | ) | |||||||||
Foreign exchange | 37 | 37 | 289 | 59 | ||||||||||||
Increase (decrease) in long-term debt | (1,340 | ) | (592 | ) | (1,564 | ) | 8,735 | |||||||||
Deferred financing costs | — | — | (167 | ) | — | |||||||||||
Stock options exercised | — | — | 328 | — | ||||||||||||
Net cash flow | (410 | ) | 563 | (2,148 | ) | (9,069 | ) | |||||||||
Beginning cash | 1,852 | 3,027 | 3,590 | 12,659 | ||||||||||||
Ending cash | $ | 1,442 | $ | 3,590 | $ | 1,442 | $ | 3,590 | ||||||||
-END-
