Find Energy Ltd.
TSX : FE

Find Energy Ltd.

August 10, 2005 16:01 ET

Find Energy Ltd. Announces Second Quarter 2005 Results

CALGARY, ALBERTA--(CCNMatthews - Aug. 10, 2005) - Find Energy Ltd. (TSX:FE) ("Find" or the "Company") is pleased to announce its financial and operational results for the six months ended June 30, 2005. This message should be read in conjunction with the attached Management's Discussion and Analysis and the associated Financial Statements for the three-month and six-month periods ended June 30, 2005.

During the three-month period ended June 30, 2005, Find Energy achieved record production volumes, cash flow and profitability. Drilling in the Pembina area of Alberta continues to be successful and preparations for the construction of a 30 mmcf per day gas plant, expected to be completed and on stream by the end of the year, are well underway.

On June 21, 2005, Find closed the sale of its properties in southeast Saskatchewan for proceeds of $29 million. These properties produced approximately 580 boe per day or 16 percent of the Company's average production during the three months. The sale proceeds, combined with the $50 million debt facility put in place in May, are underpinning the financial strength of the Company.



Highlights
Q2 2005 Q1 2005 % Change
--------- --------- ----------
Financial Results
Revenue ($000) 15,051 12,216 23
Cash flow ($000) 8,370 6,874 22
Per share ($) 0.25 0.20 25
Net income ($000) 2,116 1,393 52
Per share ($) 0.06 0.04 50
Cash flow netback ($/boe) 26.22 25.03 5
Royalties ($/boe) 11.06 9.99 11
Operating expenses ($/boe) 7.62 8.63 (12)
General and administrative costs ($/boe) 1.20 0.99 21
Capital expenditures ($000) 8,424 18,185 (54)
Debt plus working capital deficiency
($000) 1,978 29,339 (93)
Shares outstanding (000) 33,366 33,542 (1)

Production Volumes
Natural gas (mcf/day) 11,233 8,535 32
Oil and NGL (bbls/day) 1,636 1,630 -
Total (boe/day) 3,508 3,053 15


Production and Operations

Production:

Production growth during the past three months was substantial. Production averaged 3,508 boe per day, comprised of 11.2 mmcf per day of natural gas and 1,636 bbls per day of oil and natural gas liquids (NGL). The combined rate was up by 15 percent from average production for the first three months of the year of 3,053 boe per day. During the first six months of the year, production averaged 3,282 boe per day, 41 percent greater than in the same period of 2004.

Currently the Company is producing approximately 3,100 boe per day, comprised of 12.3 mmcf per day and 1,050 bbls per day of oil and NGL. The decline in average daily volume reflects the recent sale of approximately 580 boe per day of non-core production in southeast Saskatchewan.

Drilling:

During the six months ended June 30, 2005, Find drilled 20 (12.7 net) wells resulting in 17 (10.7 net) natural gas wells and three (2.0 net) dry holes for an overall success rate of 84 percent.

Of the wells drilled, eight (5.5 net) were drilled in the Pembina area of Alberta, five (3.3 net) were drilled in the Whitecourt, Alberta area and the remainder were drilled at Thorsby, Bigstone and Willesden Green, Alberta.

Land:

During Q2, Find acquired 5,760 acres of net undeveloped land while 3,150 net undeveloped acres expired and 2,984 net undeveloped acres were sold in the southeast Saskatchewan transaction, leaving the Company with a total of 134,250 net undeveloped acres of land.

Following the end of the quarter, Find reached an agreement to farm-in on 4.5 sections of land at Pembina. Operations on these lands will be conducted by Find and, if completely earned, would add 1,728 net acres of land to the Company's inventory. The farm-in brings the total acreage in which Find holds interests at Pembina to 27,680 acres, and its net undeveloped land at this area to 13,736 acres. The Company is the operator of all of these lands and holds a weighted average working interest of approximately 72 percent.

Pembina Gas Plant:

In July, Find obtained authorization to construct a natural gas processing plant in the Pembina area. The plant will have an operating capacity of 30 mmcf per day. The estimated cost of this project is $16.5 million. Find will be the operator of the construction project and the completed plant.

As well, Find will own 85 percent or 25.5 mmcf per day of its through-put capacity. Currently Find estimates it will require approximately 20 mmcf per day of capacity for its working interest share of natural gas production. Find will use its remaining capacity to process natural gas owned by partners produced from joint interest wells.

An added benefit of the new gas plant will be its ability to convert condensate into "frac oil". Frac oil is a high-value product required in well-completion operations. Frac oil is currently in relatively short supply and sells for a premium price. This provides an opportunity for Find to add value to a commodity and reduce the cost of completing Company-operated wells.

At present, Find operates 12 (7.7 net) producing gas wells and one (0.75 net) oil well in the Pembina area. Gross production is approximately 11.0 (6.2 net) mmcf per day and 800 (435 net) bbls per day of oil and NGL. An additional seven (4.5 net) wells have been drilled, completed and tested, resulting in estimated additional production of 8.2 (6.0 net) mmcf per day and 615 (385 net) bbls per day of oil and NGL or approximately 1,380 boe per day net to Find.

The Company continues to drill aggressively on its Pembina lands. Find plans to keep two rigs active between now and year-end, drilling an additional planned 29 (19.5 net) wells.

Financial

Revenue from the Sale of Oil and Natural Gas:

Revenue increased to $15.1 million in Q2 from $12.2 million in Q1, an increase of 23 percent. On a boe basis, revenue also increased, with revenue of $47.14 per boe in Q2 compared to $46.18 per boe in Q1, a result of higher average natural gas prices.

Operating Costs:

During Q2 Find incurred operating costs of $7.62 per boe of production, compared to $8.63 per boe in Q1, a reduction of 12 percent. With the sale of the southeast Saskatchewan properties, which were among the highest-cost Company-operated properties, additional improvement is anticipated for the remainder of the year. Operating costs per boe are forecast to improve further in 2006 as the impact of lower costs at the Find-operated gas plant at Pembina are realized.

Cash Flow:

During Q2 Find generated cash flow of $8.4 million, up by 22 percent over the $6.9 million realized in Q1. On a per share basis, cash flow increased to $0.25 per share, a gain of 25 percent from the $0.20 per share achieved in Q1. The cash flow to revenue ratio in Q2 was 56 percent, essentially unchanged from Q1.

Find's cash flow netback on a boe basis also improved during Q2, reaching $26.22 per boe, up by 5 percent from $25.03 per boe in Q1.

Net Income:

Find generated net income during Q2 of $2.1 million or $0.06 per share. An increase of 50 percent from $0.04 in the previous quarter.

Bank Debt and Working Capital:

During Q2, Find sold its properties in southeast Saskatchewan, resulting in a significant improvement in liquidity. The Company ended the quarter with total debt including working capital of $2.0 million. This represents a reduction in total debt of $27.4 million when compared to $29.4 million at March 31, 2005.

On May 27, 2005, Find entered into an agreement providing for a revolving loan facility of $50 million at the lender's prime rate of interest. At this time the loan facility is unutilized.

On July 29, 2005, the Company announced a bought-deal financing agreement to sell 1 million flow-through common shares at $7.60 per share for gross proceeds of $7.6 million. The transaction is expected to close on August 18, 2005.

2005 Capital Expenditures Budget

The 2005 capital program was reviewed with the Company's Board of Directors on August 10, 2005. The estimated total capital requirement for the year is now $80 million, an expansion from the previous approved capital expenditures budget of $60 million. This includes $14.4 million for Find's share of the Pembina gas plant along with an increase in funding for completions and tie-ins due to the lower-than-expected number of dry holes. Also, recent success at Whitecourt, Alberta has caused Find to purchase additional lands and drill four (2.9 net) more wells than anticipated.

Find's recent loan agreement and bought-deal financing will provide adequate financial resources to fund the remaining capital requirements for 2005.

Outlook

Find is in an excellent position to realize the value in its substantial landholdings at Pembina. Drilling has been successful and restrictions on natural gas processing capacity are being resolved by the construction of the Find-operated gas plant. As well, Find is making substantial progress towards establishing additional operating areas, with Whitecourt, Alberta showing promise. The Company's financial resources have been strengthened and are sufficient to satisfy the capital requirements for 2005.

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This news release contains information regarding estimated net present values of reserves. It should not be assumed that the estimates of net present value of the reserves represents the fair market value of the reserves.

Investors are further cautioned that the preparation of financial statements in accordance with Canadian generally accepted accounting principles ("GAAP") requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes.

Cash flow from operations and cash flow netbacks are not recognized measures under GAAP. Management believes that in addition to net income, cash flow from operations and cash flow netbacks are useful supplemental measures as they demonstrate Find's ability to generate the cash necessary to repay debt or fund future growth through capital investment. Investors are cautioned, however, that these measures should not be construed as an alternative to net income determined in accordance with GAAP as an indication of Find's performance. Find's method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to measures used by other companies. For these purposes, Find defines cash flow from operations as cash provided by operations before changes in non-cash operating working capital and defines cash flow netbacks as revenue less royalties and operating expenses.

Find has adopted the standard of 6 mcf of natural gas being equivalent to 1 barrel of oil when converting natural gas to barrels of oil equivalent (boe). This practice may be misleading, particularly if used in isolation. A 6:1 conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

This news release contains certain forward-looking statements, which are based on Find's current internal expectations, estimates, projections, assumptions and beliefs. Some of the forward-looking statements may be identified by words such as "expects", "anticipates", "believes", "projects", "plans" and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties, many of which are beyond Find's control. Such forward-looking statements necessarily involve known and unknown risks and uncertainties, which may cause Find's actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits Find will derive from them. The risks and uncertainties associated with the forward-looking statements included in this news release include, among other things, changes in general economic, market and business conditions; changes or fluctuations in production levels, unexpected drilling results, commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; changes to legislation, investment eligibility or investment criteria; Find's ability to comply with current and future environmental or other laws; Find's success at acquisition, exploration and development of reserves; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; and the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties. Many of these risks and uncertainties are described in Find's Revised Annual Information Form and Find's Management's Discussion and Analysis. Readers are also referred to risk factors described in other documents Find files with Canadian securities authorities. Copies of these documents are available without charge from Find. Find disclaims any responsibility to update these forward-looking statements.

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FIND ENERGY LTD.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This management's discussion and analysis ("MD&A") dated August 2, 2005, should be read in conjunction with the statutory filings of Find Energy Ltd. ("Find" or the "Company"). The filings include the Annual Information Form, the Statement of Reserves Data and Other Information, the audited Annual Financial Statements and MD&A along with the interim financial statements. They are available on SEDAR at www.sedar.com and on the Company's website at www.findenergy.ca.

In this MD&A, the calculation of boe is based on the conversion rate of six thousand cubic feet of natural gas for one barrel of oil. This conversion conforms to National Instrument 51-101 - Standards for Oil and Gas Activities of the Canadian Securities Administrators. Readers are cautioned that boes may be misleading if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

This MD&A contains forward-looking statements. Forward-looking statements are based on current expectations that involve a number of risks and uncertainties which could cause actual events or results to differ materially from those reflected in the MD&A. Forward-looking statements are based on the estimates and opinions of Find's management at the time the statements were made.

The MD&A contains the term cash flow from operations, which should not be considered an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with Canadian generally accepted accounting principles as an indicator of the Company's performance. Find's calculation of cash flow from operations may not be comparable to that reported by other companies. Cash flow from operations per share is calculated using the same weighted average number of shares outstanding used in the calculation of income per share.

The terms "2005 H1", "2005 Q2", "2005 Q1" and "2004 H1" refer to the six months ended June 30, 2005, the three months ended June 30, 2005, the three months ended March 31, 2005 and the six months ended June 30, 2004.



Volumes

2005 2005 2005 2004
H1 Q2 Q1 H1
-------- -------- -------- --------
Natural Gas (mcf/day) 9,891 11,233 8,535 5,675
Oil and NGLs (bbls/day) 1,633 1,636 1,630 1,374
-------- -------- -------- --------
Total (boe/day) 3,282 3,508 3,053 2,320
-------- -------- -------- --------
-------- -------- -------- --------


On a total production basis, second quarter 2005 production was 15 percent higher than first quarter 2005 production and production for the six months ended June 30, 2005 was 41 percent higher than for the same period in 2004.

Natural gas production grew by 32 percent over the first quarter of 2005. Natural gas production was 74 percent higher in the six months of 2005 when compared to the first half of 2004.

The growth in gas production volumes from the first quarter to the second quarter was led by Pembina West. Gas production at Pembina West was 5.4 Mmcfd in the second quarter, an increase of 125 percent over the 2.4 Mmcfd produced in the first quarter.

Crude oil and NGL volumes were flat from the first quarter to the second quarter. For the six months ended June 30, 2005, they were 19 percent higher than the six months ended June 30, 2004.



Product Pricing

2005 2005 2005 2004
Natural Gas ($/mcf) H1 Q2 Q1 H1
-------- -------- -------- --------
Price before hedging 7.48 7.63 7.28 6.99
Hedging gain (loss) - - - -
-------- -------- -------- --------
Net price 7.48 7.63 7.28 6.99
-------- -------- -------- --------
-------- -------- -------- --------
AECO daily index 7.11 7.36 6.85 6.70

Nymex (US$/mcf) 6.72 6.95 6.48 5.95


Find's realized gas price increased by $0.35 in the second quarter, an improvement of five percent over the $7.28 received in the first quarter of 2005. AECO daily index was up seven percent in the quarter when compared to the first quarter as the Company's historical premium to AECO pricing was maintained.

Gas prices were certainly carried along by much stronger crude oil prices in the second quarter. This occurred despite the fact that U.S. natural gas inventories ended the traditional withdrawal season at levels well above historical averages. As the injection season is now well underway, it is noteworthy that weekly injections are coming in much lower than historical averages. The Company believes that this bodes well for natural gas prices in the near and medium term.

Find's realized natural gas price was seven percent higher in the first six months of 2005 when compared to 2004. The Company had no natural gas price hedges in place in the first six months of the year and has not entered into any subsequent to the end of the second quarter.



2005 2005 2005 2004
Oil and Natural Gas Liquids ($/bbl) H1 Q2 Q1 H1
-------- -------- -------- --------
Price before hedging 48.52 48.71 48.32 41.16
Hedging gain (loss) (1.58) - (3.19) (3.30)
-------- -------- -------- --------
Net price 46.94 48.71 45.13 37.86
-------- -------- -------- --------
-------- -------- -------- --------
WTI (US$/bbl) 51.37 53.03 49.69 36.77

Edmonton light ($/bbl) 64.22 66.42 62.04 48.62

CDN$/US$ 0.8095 0.804 0.815 0.7473


Find's oil price before hedging was virtually unchanged from the first quarter to the second quarter. This lack of change is noteworthy as both WTI and Edmonton Light crude prices increased by approximately seven percent in the quarter. Find's corporate differential to Edmonton Light widened to $17.71 per bbl in the second quarter from $13.72 per bbl in Q1. Differentials continue to widen as a greater portion of the world's crude supplies become heavier and there is a relative lack of facilities to process this crude. Most of Find's crude oil production in the second quarter was light with only approximately 25 percent being medium and heavier crude. After the sale of the southeast Saskatchewan assets, the Company expects a much lower selling price for its crude oil as all of the southeast Saskatchewan production is light oil.

The sale of southeast Saskatchewan had a marginal impact on Find's Q2 production, as the transaction didn't close until June 22. At the time of closing, the assets in southeast Saskatchewan were producing 580 boed.



Income Statement

2005 2005 2005 2004
Revenue H1 Q2 Q1 H1
-------- -------- -------- --------
Oil & natural gas sales,
before hedging ($000) 27,736 15,051 12,684 17,510
Per boe ($) 46.69 47.14 46.18 41.48
Hedging loss ($000) 468 - 468 826
Per boe ($) 0.79 - 1.70 1.96


Revenue for the three months ended March 31, 2005 ($000) 12,684
Increase in commodity prices ($000) 323
Increase in production volumes ($000) 2,044
---------
Revenue for the three months ended June 30, 2005 ($000) 15,051
---------
---------


2005 2005 2005 2004
Royalties H1 Q2 Q1 H1
-------- -------- -------- --------
Total Royalties ($000) 6,278 3,532 2,746 3,839
% of revenue before hedging 22.6 23.5 21.6 21.9
Per boe ($) 10.57 11.06 9.99 9.09


Royalty rates climbed during the quarter as production from Pembina West continued to grow. Pembina West is classified as "new gas" and so attracts the highest crown royalty rate. Due to the Company's size, these royalties are only minimally offset by ARTC.



2005 2005 2005 2004
Operating Expenses H1 Q2 Q1 H1
-------- -------- -------- --------

Total lease operating ($000) 4,804 2,432 2,372 4,403

Per boe ($) 8.09 7.62 8.63 10.43


Lease operating costs continued to decline, falling by 12 percent to $7.62 when compared to the first quarter of 2005. Cost reduction initiatives in all operated properties were fully realized. Find also realized corporate cost reductions due to an increased volume of production coming from Pembina West, which is proving to be a low cost operating area. Additional cost savings on a corporate basis are anticipated following the sale of southeast Saskatchewan.

For the six months ended June 30, 2005, operating costs were $8.09 per boe or 22 percent lower than the operating costs for the same period a year earlier.



2005 2005 2005 2004
General & Administrative ($000) H1 Q2 Q1 H1
-------- -------- -------- --------
Total G & A expense 2,348 1,343 1,005 2,214
Recoveries (790) (380) (410) (484)
Capitalized (903) (581) (322) (561)
-------- -------- -------- --------
Net 655 382 273 1,169
-------- -------- -------- --------
-------- -------- -------- --------

Per boe ($) 1.10 1.20 0.99 2.77


General and administrative costs were up on a gross basis, as the Company incurred employee retention costs as well as costs associated with year end reporting. Recoveries from capital projects were virtually the same as the first quarter, despite lower capital expenditures, as the Company commenced drilling new wells which were able to capture a higher overhead recovery rate.

Gross general and administrative costs were virtually the same for the two six-month periods. The Company believes it can still increase production while maintaining the same general and administrative cost structure.



2005 2005 2005 2004
Interest Expense ($000) H1 Q2 Q1 H1
-------- -------- -------- --------
Total interest expense ($000) 332 216 116 386

Per boe ($) 0.56 0.68 0.42 0.91


Interest expense was higher in the second quarter as the Company carried a much higher average loan balance for the period. The sale of southeast Saskatchewan did not close until June 22 so the impact on interest expense during the period was minimal. The prime rate remained constant for both periods at 4.25 percent.



2005 2005 2005 2004
Provision for Taxes ($000) H1 Q2 Q1 H1
-------- -------- -------- --------
Future income taxes 2,727 1,614 1,113 305
Current tax expense - - - -
Capital tax expense 331 190 141 349
-------- -------- -------- --------
Total tax expense 3,058 1,804 1,254 654
-------- -------- -------- --------
-------- -------- -------- --------


Capital tax expense was higher in the second quarter due to an under provision of Saskatchewan Resource Surcharge from the first quarter.



2005 2005 2005 2004
Stock-based Compensation ($000) H1 Q2 Q1 H1
-------- -------- -------- --------
Total stock-based compensation 734 390 344 475
Capitalized (285) (158) (127) (146)
-------- -------- -------- --------
Net 449 232 217 329
-------- -------- -------- --------
-------- -------- -------- --------
Per boe ($) 0.76 0.73 0.79 0.78


Stock-based compensation is a non-cash calculation that attempts to value stock options at the time they are granted. As the Company had very little change in outstanding options in the second quarter, there was only a slight change in the expensed amount.



Depletion, Depreciation and 2005 2005 2005 2004
Accretion H1 Q2 Q1 H1
-------- -------- -------- --------
Total DD&A ($000) 8,186 4,408 3,778 5,453

Per boe ($) 13.78 13.81 13.75 12.91


Depletion, depreciation and accretion provision was virtually unchanged on a boe basis in the second quarter when compared to the first. While capital spending was down in the quarter, reserve additions were at the Company's historical depletion rate, causing little change in per boe depletion.



2005 2005 2005 2004
Net Income ($000) H1 Q2 Q1 H1
-------- -------- -------- --------
Net income 3,509 2,117 1,393 547
Per boe ($) 5.91 6.63 5.07 1.30
Per share ($) 0.10 0.06 0.04 0.02
Weighted average shares
outstanding (000) 33,550 33,558 33,542 26,461


Net income was up strongly in the second quarter, growing by 52 percent to $2.1 million as compared to the $1.4 million recorded in the first quarter of 2005. For the six months ended June 30, 2005, net income was 541 percent greater than the $547,000 of net income recorded in the first six months of 2004.



2005 Q2 2005 Q1
------------------ ------------------
$000 $/boe $000 $/boe
------------------ ------------------
Revenue, net of hedging and
realized gain on financial
instrument 15,122 47.37 12,522 45.57
------------------ ------------------

Royalties 3,532 11.06 2,746 9.99
Operating Expenses 2,432 7.62 2,372 8.63
General and administrative 382 1.20 273 0.99
Interest 216 0.68 116 0.42
Capital taxes 190 0.59 141 0.51
------------------ ------------------
6,752 21.15 5,648 20.54
------------------ ------------------
------------------ ------------------

Cash flow from operations 8,370 26.22 6,874 25.03

Depletion, depreciation
& accretion 4,408 13.81 3,778 13.75
Unrealized gain on financial
instrument - - 372 1.35
Stock-based compensation 232 0.73 217 0.79
Future taxes 1,614 5.05 1,113 4.05
------------------ ------------------
Net income 2,116 6.63 1,393 5.07
------------------ ------------------
------------------ ------------------


Liquidity and Capital Resources

2005 2005 2005 2004
Cash Flow from Operations H1 Q2 Q1 H1
-------- -------- -------- --------
Cash flow from operations ($000) 15,244 8,370 6,874 6,633
Cash flow netback, per boe ($) 25.66 26.22 25.03 15.71
Cash flow as a percentage of
revenue 55.0% 55.6% 54.2% 37.9%
Cash flow from operations,
per share ($) 0.45 0.25 0.20 0.25
Weighted average shares
outstanding (000) 33,550 33,558 33,542 26,461


Cash flow was up significantly in the second quarter of 2005 compared to the first quarter. Total cash flow grew by 22 percent to $8.3 million; on a per share basis it grew by 25 percent to $0.25. This growth was driven by increased average commodity prices (up 4 percent) and a large increase in production volumes (up 15 percent). Cash costs were up 3 percent from the first quarter.



2005 2005 2004
Capital Expenditures ($000) Q2 Q1 Q4
-------- -------- --------
Land and seismic (27,867) 820 (1,309)
Drilling and completions 6,107 11,742 16,460
Well equipment and facilities 1,258 5,301 1,183
-------- -------- --------
(20,502) 17,863 16,334
Capitalized G & A 580 322 431
-------- -------- --------
Total capital expenditures (19,922) 18,185 16,765
-------- -------- --------
-------- -------- --------


Capital Expenditures by Area
(Six Months ended June 30, 2005)

Land/ Drill/ Equip/
Area ($000) Seismic Comp. Facilities Total
--------- -------- ----------- --------

West Central 893 15,586 4,961 21,440
East Central (13) 2,115 406 2,508
SE Saskatchewan (28,361) 147 276 (27,938)
Other 435 - 916 1,351
--------- -------- ----------- --------
(27,046) 17,848 6,559 (2,639)
--------- -------- ----------- --------
--------- -------- ----------- --------


Sale of Southeast Saskatchewan

On June 22, Find closed the sale of all of its southeast Saskatchewan assets. Net proceeds from the sale amounted to $29 million.

The properties had total assigned proved reserves of 1.9 million barrels and proved plus probable reserves of 2.5 million barrels. Production at the time of the sale was 580 boed. Find operated only 47 percent of the assets and had an average working interest of 38 percent.

Proceeds from the disposition will be employed in the Company's growth areas, primarily at Pembina West in Alberta. Find is the operator of Pembina West and holds an average working interest of 65 percent.

In addition, the sale is expected to have a positive impact on Find's operating costs, while freeing up staff to spend more time on higher rate of return opportunities.



Wells Drilled by Area
(Six Months ended June 30, 2005)

Area Gas Oil D & A Total Success
---------- ---------- ---------- ---------- --------
Gross Net Gross Net Gross Net Gross Net Rate
---------- ---------- ---------- ---------- --------
West Central 16 9.9 - - 3 2.0 19 11.9 83%
East Central 1 0.8 - - - - 1 0.8 100%
SE Sask - - - - - - - - -
Other - - - - - - - - -
---------- ---------- ---------- ---------- --------
17 10.7 - - 3 2.0 20 12.7 84%


New Bank Line

After the sale of the southeast Saskatchewan assets, Find has entered into a new loan agreement with its principal lender. This agreement is a Revolving Operating Loan Facility in the amount of $50 million. Borrowing under the facility bear interest at prime or at Base Rate plus 1.25 percent on guaranteed rates. The facility is subject to review in June 2006.

Flow-Through Share Financing

On July 29, 2005, Find entered into a bought-deal financing with a syndicate of underwriters to issue 1.0 million flow-through common shares on a private placement basis at a price of $7.60 per share. Proceeds after expenses are expected to be approximately $7.0 million. The financing is expected to close on August 18, 2005.

Normal Course Issuer Bid

On May 31, 2005, Find filed a Notice of Intention to make a normal course issuer bid through the Toronto Stock Exchange "TSX". Find intends to use the bid to purchase and cancel shares at prices that are not reflective of the current fair value of Find shares relative to its assets, opportunity base and competitors' valuations. The Company intends to finance the issuer bid through cash flow and bank lines of credit.

As of June 30, 2005, Find had purchased 242,800 shares at an average cost including commission of $4.19 per share.

Sensitivities

A critical component in Find's growth plan is the Company's cash flow. Cash flow represents funds available for reinvestment in capital projects. Among the various components that affect cash flow, management has determined that the price of oil and natural gas have the most impact on the Company's cash flow. Of course, adding production volumes with the highest possible netback also has a very meaningful impact on available cash flow. The CDN dollar exchange rate is the factor that has the next largest impact, while changes in interest rates have very little impact. The following table illustrates the sensitivity of Find's cash flow to changes in natural gas prices, oil prices and the CDN dollar.



Annual Cash Flow Cash Flow
($000) per Share
------------------ -----------
100 Boed of production 1,260 $0.04
Crude oil - WTI price change of $1.00 US/bbl 460 $0.01
Natural gas - AECO price change of $0.25/mcf 934 $0.03
CDN$ - change of $0.01 US 346 $0.01


Selected Supplemental Information ($000)

Dec. 31, Dec. 31, Dec. 31,
2004 2003 2002
--------- --------- ---------
Petroleum and natural gas sales 34,681 8,931 -
Income (loss) for the year 2,905 (1,130) (327)
Income (loss) per share-basic & diluted 0.10 (0.08) (0.03)
Total assets 116,054 79,269 8,805
Total liabilities 31,966 26,787 1,601


2004 2004 2003 2003
Q2 Q1 Q4 Q3
-------- -------- -------- --------
Petroleum & natural gas sales 9,805 7,705 6,125 1,639
Income (loss) for the quarter 877 (330) (520) (476)
Income (loss) per share - basic
& diluted 0.03 (0.01) (0.02) (0.04)


2005 2005 2004 2004
Q2 Q1 Q4 Q3
-------- -------- -------- --------
Petroleum & natural gas sales 15,051 12,684 10,029 8,814
Income for the quarter 2,117 1,393 960 1,398
Income per share - basic
& diluted 0.06 0.04 0.03 0.05


Estimated Tax Pools ($million)

June 30, 2005
---------------

Canadian oil & gas property expense -
Canadian development expense 26.0
Canadian exploration expense 15.1
Tangibles 15.1
Non-capital losses 2.8
Financing expenses 2.3
---------------
61.3
---------------
---------------


Off-Balance Sheet Arrangements

Find currently does not have any off-balance sheet arrangements with any party, and does not currently expect to enter into any such arrangements for the balance of 2005.

Transactions with Related Parties

During the first half of 2005, the Company had no transactions with any related parties.

Financial Reporting and Regulatory Update

The Company was not subjected to any new financial reporting or regulatory requirements in the second quarter of 2005 and is not aware of any impending changes over the balance of the year.

Critical Accounting Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect assets, liabilities, revenues and expenses. Management is also required to adopt accounting policies that require the use of significant estimates. Find's management believes the most critical accounting estimates that may have an impact on the Company's results are in the non-cash areas of accounting for property, plant & equipment, asset retirement obligations, and stock based compensation.

Property, Plant & Equipment

Find follows the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to the acquisition of, exploration for and development of oil and natural gas reserves are capitalized. These costs are then systematically charged to income through a depletion, depreciation and amortization (DD&A) calculation. This calculation is based on the unit of production method which amortizes the cost of oil and gas assets over the Company's proved oil and gas reserve base. Proved reserves are determined by the Company using the guidelines of National Instrument 51-101. Changes to proved reserves in the future could increase or decrease the amount of the Company's DD&A.

A ceiling test calculation is required each time financial statements are prepared. The test limits the carrying value of the Company's property and equipment to the estimated net present value of future cash flows from the proved and probable reserves. At June 30, 2005, Find had a ceiling test cushion of approximately $37 million.

The full cost accounting guidelines allow for the cost of unproved properties to be excluded from the DD&A calculation. For the three months ended June 30, 2005, Find excluded $12.9 million from costs subject to DD&A. These costs are assessed quarterly for impairment. Should the judgment be made that these costs are impaired, an increase to DD&A will result.

Asset Retirement Obligations

Under the asset retirement obligations rules, the total fair value of the Company's retirement obligations are set up on the balance sheet at the discounted future value of the liability. The key areas of judgment are in determining the amount of the future liability, the appropriate discount rate and when the expenditures will be incurred. External factors influencing these obligations include commodity prices, interest rates and changes to regulatory requirements. Dramatic changes in any of these could result in an increase or decrease in net income.

Stock-based Compensation

Find is required to calculate the fair value of stock options at the time of grant and charge this to income in a systematic manner over the vesting period of the options. The calculation method that Find has adopted to calculate the fair value of options is the Black-Scholes model. The most critical estimate in the Black-Scholes model is the expected volatility of Find's shares. Management has determined that 50 percent is an appropriate volatility rate for Find. Actual volatility could be more or less than 50 percent which could have a material impact on net income.

Share Capital

As at August 2, 2005, the Corporation has 32,923,376 shares and 3,330,000 stock options outstanding.



FIND ENERGY LTD.
Consolidated Balance Sheets
June 30, 2005 and December 31, 2004

June 30, December 31,
2005 2004
----------------- -------------------
$ $
----------------- -------------------
(unaudited) (audited)
----------------- -------------------
ASSETS

CURRENT
Cash and cash equivalents 13,554,200 200
Accounts receivable 9,889,140 11,528,233
Note receivable (Note 2) 737,500 2,212,500
Prepaid expenses 403,668 196,374
Foreign exchange contracts
(Note 10(a)) - 372,060
----------------- -------------------
24,584,508 14,309,367

Deposits and other (Note 3) 322,774 230,761
Property and equipment (Note 4) 91,690,432 101,514,146
----------------- -------------------
116,597,714 116,054,274
----------------- -------------------
----------------- -------------------

LIABILITIES

CURRENT
Accounts payable and
accrued liabilities 17,902,464 22,785,505
Income taxes payable 89,706 26,400
Bank indebtedness (Note 6) 8,571,049 9,153,618
----------------- -------------------
26,563,219 31,965,523
----------------- -------------------
Asset retirement obligations
(Note 5) 3,076,876 3,263,675
----------------- -------------------
Future income taxes 8,685,412 5,958,016
----------------- -------------------

SHAREHOLDERS' EQUITY

Share capital (Note 8) 71,818,221 72,076,343
Contributed surplus 1,992,260 1,343,471
Retained earnings 4,461,726 1,447,246
----------------- -------------------
78,272,207 74,867,060
----------------- -------------------
116,597,714 116,054,274
----------------- -------------------
----------------- -------------------

Commitments and contingencies (Note 10)

The accompanying notes are an integral part of these financial
statements.


FIND ENERGY LTD.
Consolidated Statements of Operations and Retained Earnings (Deficit)
For the six month period ended June 30
Unaudited

Three Months ended Six Months ended
June 30 June 30
----------------------- -----------------------

2005 2004 2005 2004
----------- ----------- ----------- -----------
$ $ $ $
----------- ----------- ----------- -----------
REVENUE
Petroleum and natural
gas sales 15,051,404 9,382,509 27,267,828 16,683,236
Royalties 3,532,089 2,133,776 6,278,069 3,839,375
----------- ----------- ----------- -----------
11,519,315 7,248,733 20,989,759 12,843,861
Interest and other 71,149 12,854 71,811 96,147
Realized loss on
financial instruments
(Note 10(a)) - - (67,685) -
----------- ----------- ----------- -----------
11,590,464 7,261,587 20,993,885 12,940,008
----------- ----------- ----------- -----------

EXPENSES
Operating 2,432,182 2,113,614 4,803,725 4,403,489
General and
administrative 382,366 516,333 655,481 1,168,908
Interest 216,098 185,941 332,285 385,668
Depletion,
depreciation
and accretion 4,407,591 2,877,244 8,186,068 5,452,906
Stock-based
compensation
(Note 8(e)) 231,784 169,776 448,676 328,324
----------- ----------- ----------- -----------
7,670,021 5,862,908 14,426,235 11,739,295
----------- ----------- ----------- -----------
Income before taxes 3,920,443 1,398,679 6,567,650 1,200,713
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------

Provision for taxes
(Note 7)
Capital 189,778 216,749 330,802 348,937
Future 1,613,931 304,674 2,727,396 304,674
----------- ----------- ----------- -----------
1,803,709 521,423 3,058,198 653,611
----------- ----------- ----------- -----------
Income for the period 2,116,734 877,256 3,509,452 547,102
Retained earnings/
(deficit), beginning
of the period 2,839,964 (1,787,689) 1,447,246 (1,457,535)
Excess of cost of
shares acquired over
stated value
(Note 8(d)) (494,972) - (494,972) -
----------- ----------- ----------- -----------
Retained earnings/
(deficit), end
of period 4,461,726 (910,433) 4,461,726 (910,433)
----------- ----------- ----------- -----------
Income per share
Basic and diluted 0.06 0.03 0.10 0.02
----------- ----------- ----------- -----------
Weighted average
number of shares
- basic (Note 9) 33,557,974 26,980,279 33,550,089 26,460,896
----------- ----------- ----------- -----------
Total number of
shares outstanding,
end of period
(Note 8(b)) 33,365,976 29,442,110 33,365,976 29,442,110
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------

The accompanying notes are an integral part of these financial
statements.


FIND ENERGY LTD.
Consolidated Statements of Cash Flows
For the six month period ended June 30
Unaudited

Three Months ended Six Months ended
June 30 June 30
----------------------- -----------------------

2005 2004 2005 2004
----------- ----------- ----------- -----------
$ $ $ $
----------- ----------- ----------- -----------

CASH FLOWS RELATED TO THE
FOLLOWING ACTIVITIES:

OPERATING

Income for the period 2,116,734 877,256 3,509,452 547,102
Adjustments for:
Unrealized gain on
financial instruments
(Note 10(a)) - - 372,060 -
Depletion, depreciation
and accretion 4,407,591 2,877,244 8,186,068 5,452,906
Stock-based compensation 231,784 169,776 448,676 328,324
Future income taxes 1,613,931 304,674 2,727,396 304,674
----------- ----------- ----------- -----------
8,370,040 4,228,950 15,243,652 6,633,006
Changes in non-cash
working capital 3,546,747 (364,607) 1,634,674 (1,234,592)
----------- ----------- ----------- -----------
11,916,787 3,864,343 16,878,326 5,398,414
----------- ----------- ----------- -----------
FINANCING
Issue of shares, net of
share issue costs 177,911 11,295,784 179,031 11,248,580
Bank indebtedness (14,173,243) (3,944,982) (582,569) 2,245,987
Redemption of share
capital - normal
course issuer bid (1,017,457) - (1,017,457) -
Changes in non-cash
working capital (178,665) - (178,665) -
----------- ----------- ----------- -----------
(15,191,454) 7,350,802 (1,599,660) 13,494,567
----------- ----------- ----------- -----------
INVESTING
Property and equipment (8,558,608)(10,094,010)(26,771,375)(16,265,207)
Other deposits (92,013) (20,218) (92,013) (7,213)
Proceeds on sale of
properties 28,480,166 - 28,507,666 -
Changes in non-cash
working capital (3,000,878) (1,104,222) (3,368,944) (2,622,723)
----------- ----------- ----------- -----------
16,828,667 (11,218,450) (1,724,666)(18,895,143)
----------- ----------- ----------- -----------
Net increase/(decrease)
in cash and cash
equivalents 13,554,000 (3,305) 13,554,000 (2,162)
Cash and cash
equivalents, beginning
of period 200 24,521 200 23,378
----------- ----------- ----------- -----------
Cash and cash
equivalents, end of
period 13,554,200 21,216 13,554,200 21,216
----------- ----------- ----------- -----------
Taxes paid during the
period 303,069 247,394 336,414 605,261
----------- ----------- ----------- -----------
Interest paid during
the period 169,051 168,386 301,016 350,516
----------- ----------- ----------- -----------

The accompanying notes are an integral part of these financial
statements.


FIND ENERGY LTD.
Notes to the Consolidated Financial Statements
June 30, 2005
Unaudited


1. SIGNIFICANT ACCOUNTING POLICIES

The interim consolidated financial statements of Find Energy Ltd. (the "Corporation") have been prepared by management in accordance with accounting principles generally accepted in Canada. The interim consolidated financial statements have been prepared following the same accounting principles and methods of computation as those utilized in the consolidated financial statements for the year ended December 31, 2004. The disclosures provided below are incremental to those included with the annual consolidated financial statements. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes for the year ended December 31, 2004.

2. NOTE RECEIVABLE

On October 1, 2004 the Corporation sold certain Saskatchewan properties. Proceeds received include a promissory note. As at June 30, 2005, $737,500 remains outstanding, with payment in full to be received by September 30, 2005. The note receivable is secured against the properties and is non-interest bearing.

3. DEPOSITS AND OTHER

Deposits and other is comprised of deposits required under crown royalty regulations and operating lease obligations.



4. PROPERTY AND EQUIPMENT

Accumulated Net Book
Depletion and Value
Cost Depreciation June 30 2005
------------ ------------- -------------
$ $ $

Petroleum and natural gas
properties and equipment 114,157,680 22,519,799 91,637,881
Furniture and equipment 102,369 49,818 52,551
------------ ------------- -------------
114,260,049 22,569,617 91,690,432
------------ ------------- -------------
------------ ------------- -------------


Unproved properties and proprietary seismic data of $12,860,600 have been excluded from costs subject to depletion. During the first six months of 2005, the Corporation capitalized $1,188,100 (2004 - $706,700) of general and administrative expenditures and stock-based compensation related to exploration and development activities.

5. ASSET RETIREMENT OBLIGATIONS

The change in asset retirement obligation for the year ended December 31, 2004 and six month period ended June 30, 2004 and 2005 are as follows:



June 30, June 30, December 31,
2005 2004 2004
---------- --------- ------------
$ $ $

Asset retirement obligation,
beginning of period 3,263,675 3,616,855 3,616,855
Liabilities incurred 262,899 52,569 481,500
Liabilities settled (554,397) - (1,070,067)
Accretion expense 104,699 126,589 235,387
Revisions in estimated cash flows - - -
---------- --------- ------------
Asset retirement obligation,
end of period 3,076,876 3,796,013 3,263,675
---------- --------- ------------
---------- --------- ------------


The total estimated, undiscounted cash flows required to settle the obligations at June 30, 2005 without including salvage, is $5,658,176 (June 30, 2004 - $6,492,069 and December 31, 2004 - $6,131,460). These amounts have been discounted using a credit-adjusted risk-free rate of 7.0% (December 31 and June 30, 2004 - 7.0%). The Corporation expects these obligations to be settled, on average in 11.9 years, the majority of which is expected to be incurred between 2008 and 2025.

6. BANK INDEBTEDNESS

Effective May 27, 2005, the Corporation agreed to a revised credit facility comprised of a $50 million Revolving Operating Demand Loan by way of prime rate loans, banker's acceptances and letters of credit. The credit facility bears interest as follows:

- Prime-based loans - Interest is payable in Canadian dollars at Prime plus 0.0% per 365-day period;

- Guaranteed Notes - Fee is payable in Canadian dollars at Base Rate plus 1.25% per 365-day period.

The facility is subject to a review on or before June 30, 2006.

The facility is secured by a $50 million debenture with a fixed and floating charge over all assets of the Corporation and a general assignment of book debts.



The balance as of June 30, 2005 is comprised of the following:

Revolving Operating Demand Loan at prime plus 0% $ 1,775,731
Bankers Acceptance at weighted average rate of 3.88% 6,000,000
Letter of Guarantee 795,318
-------------
$ 8,571,049
-------------
-------------


The Letter of Guarantee has been issued to the Monitor appointed under the Company's Creditor Arrangement Act for Liberty Oil & Gas Ltd., a former subsidiary of Lexxor Energy Inc. The Monitor is currently settling creditor claims and the Letter of Guarantee is periodically reduced as the claims are settled by the Corporation.

7. INCOME TAXES

The provision for capital taxes reflected in the consolidated statement of operations includes Large Corporation and Saskatchewan Capital taxes and Saskatchewan Resource Surcharge.



8. SHARE CAPITAL

(a) Authorized

Unlimited number of Common Shares
Unlimited number of Preferred Shares, issuable in series

Six months ended Year ended
June 30, 2005 December 31, 2004
----------------------- -----------------------
Number of Amount Number of Amount
(b) Issued common shares Shares $ Shares $
----------------------- -----------------------
Balance January 1 33,542,110 72,076,343 25,941,163 50,098,065
Issued under Stock
Option Plan 66,666 263,997 - -
Shares repurchased
(Note 8(d)) (242,800) (522,485) - -
Issued for cash on
exercise of warrants - - 947 5,682
Issued for cash pursuant
to private placements
(Note 8(c)) - - 7,600,000 28,065,000
Future income taxes on
expenditures renounced
for flow through shares - - - (4,972,058)
----------------------- -----------------------
33,365,976 71,817,855 33,542,110 73,196,689
Share issue costs,
(2004 - net of tax of
$572,786) - 366 - (1,120,346)
----------------------- -----------------------
Balance, end of period 33,365,976 71,818,221 33,542,110 72,076,343
----------------------- -----------------------
----------------------- -----------------------


(c) On June 3, 2004, the Corporation completed a private placement of 3,500,000 flow-through common shares at a price of $3.45 per share for gross proceeds of $12,075,000. Transaction costs were $788,000 including fees paid to underwriters.

In accordance with the terms of the offering and pursuant to certain provisions of the Income Tax Act (Canada), the Corporation renounced, for income tax purposes, exploration expenditures of $12,075,000 to the holders of the flow-through common shares effective December 31, 2004. The Corporation incurred $8,574,100 of expenditures to December 31, 2004, with the remaining $3,500,900 expended in the first quarter of 2005. Future income tax cost of $4,085,000 associated with renouncing the expenditures has been recorded at December 31, 2004.

On November 10, 2004, the Corporation completed a private placement of 4,100,000 common shares at a price of $3.90 per share for gross proceeds of $15,990,000. Transaction costs were $858,000 including fees paid to underwriters.

(d) On June 2, 2005, the Corporation announced a normal course issuer bid that will allow purchase and cancellation of up to 2,422,346 common shares. This normal course issuer bid is scheduled to expire on June 1, 2006. A total of 242,800 common shares were purchased up to June 30, 2005 at a cost of $1,017,457. The excess of the cost to repurchase over the stated value of the shares of $494,972 was charged to retained earnings.

(e) Stock Option Plan

On September 10, 2003, the shareholders approved a stock option plan (the "Plan") for the Corporation. The Plan authorizes the Board to grant stock options to directors, officers, employees and consultants of the Corporation. The aggregate number of common shares reserved for issuance under the Plan was 3,300,000. The Plan also provides for options to be granted at the defined market price, and that the term of the option must be no more than five years. Stock options issued vest over a three-year period commencing on the first anniversary of, and expire five years after the date of issue.

At the June 8, 2004 Annual General Meeting, shareholders approved a change in the stock option plan from a maximum number of shares to a rolling maximum equal to 10 percent of the outstanding common shares, subject to Toronto Stock Exchange ("TSX") approval. The TSX granted their approval on January 4, 2005.



A summary of the Corporation's stock option plan as at June 30, 2005 is
as follows:

Weighted
Weighted Average
Average Remaining
Number Exercise Contractual
Continuity of stock options Of Shares Price Life (Years)
---------- -------- ------------
Outstanding, December 31, 2004 3,259,000 $2.81 4.1
Granted during the period 272,500 3.13 4.8
Exercised during the period (66,666) 2.68 -
Cancelled during the period (129,334) 2.86 3.7
---------- -------- ------------
Outstanding, June 30, 2005 3,335,500 $2.84 3.7
---------- -------- ------------
---------- -------- ------------


The following table summarizes information about the Corporation's stock
options outstanding and exercisable at June 30, 2005:

Options Outstanding Exercisable Options
----------------------------------- ----------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Number Contractual Exercise Number Exercise
Outstanding Life (Years) Price Exercisable Price
-----------------------------------------------------------

$2.30 to $2.80 2,521,600 3.5 $2.66 783,030 $2.64
$2.81 to $3.30 356,000 4.6 3.02 - -
$3.31 to $3.80 442,900 4.4 3.66 - -
$3.81 to $4.20 15,000 5.0 4.20 - -
----------------------------------- ----------------------
3,335,500 3.7 $2.84 783,030 $2.64
----------------------------------- ----------------------
----------------------------------- ----------------------


Compensation cost recognized for the six months ended June 30, 2005 related to options granted in prior years was $694,837, of which $433,940 was charged to income and $260,897 was capitalized.

The fair value of stock options granted during the six months ended June 30, 2005 was estimated using the Black-Scholes option pricing model and with the following assumptions: expected volatility (49% to 50%); risk-free interest rates (3.195% to 3.895%); expected life (5 years); and expected future dividends (nil). Stock options granted during the period had an estimated fair value of $1.34 to $1.94 per share.

Compensation cost recognized for the six months ended June 30, 2005 related to options granted in 2005 was $39,284, of which $14,736 was charged to income and $24,548 was capitalized.

9. WEIGHTED AVERAGE SHARES OUTSTANDING

The weighted average number of common shares issued and outstanding for the six months ended June 30, 2005 and June 30, 2004 are as follows:



Three Months Ended Six Months Ended
June 30 June 30
------------------------ ------------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Basic 33,557,974 26,980,279 33,550,089 26,460,896

Diluted 34,149,891 27,083,454 34,142,006 26,572,490


10. COMMITMENTS AND CONTINGENCIES

(a) Commodity marketing arrangement and foreign exchange contracts

The Corporation has a price risk management program whereby the commodity price associated with a portion of its future production is fixed. The forward and futures contracts are subject to market risk from fluctuating commodity prices and exchange rates, however, gains and losses on the contracts are offset by changes in the value of the Corporation's production and recognized in income in the same period and category as the hedged item. The Corporation also enters into foreign exchange contracts to manage foreign currency fluctuations.

As at June 30, 2005, the Corporation has no outstanding commodity marketing arrangements or foreign exchange contracts. The gain on settlement of foreign exchange contracts during the first six months is $304,375. At December 31, 2004, $372,060 of this was marked-to-market, with a net realized loss in the first six months of 2005 of $67,685.

(b) Operating commitments

In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the Corporation has entered into operating leases for office space and other property and equipment. Under contracts existing at June 30, 2005, future minimum amounts payable on a fiscal year basis, excluding operating costs, are as follows:



2005 64,218
2006 143,369
2007 23,907
-------------
231,494
-------------
-------------


(c) Dispute with Industry Partner

On August 8, 2003, a joint venture partner of the Corporation filed a statement of claim in the amount of $768,000 in respect of a dispute regarding working interest participation. A statement of defense has been filed and it is the opinion of management that this claim is without merit.

11. SUBSEQUENT EVENTS

Bought Deal Financing

On July 29, 2005, the Corporation entered into a bought deal financing arrangement to issue 1.0 million flow-through common shares at a price of $7.60 per share. The financing is expected to close on August 18, 2005 and is subject to certain conditions including, but not limited to, the receipt of all necessary approvals including the approval of the Toronto Stock Exchange.

Normal Course Issuer Bid

During July 2005, the Corporation purchased 442,600 common shares at a cost of $2,417,018.

Contact Information

  • Find Energy Ltd.
    William T. Davis
    C.E.O
    (403) 232-4802
    (403) 232-4824 (FAX)
    or
    Find Energy Ltd.
    Jeffrey P. Jongmans
    C.F.O.
    (403) 232-4809
    (403) 232-4824 (FAX)