Find Energy Ltd.

Find Energy Ltd.

November 09, 2005 16:02 ET

Find Energy Ltd. Announces Third Quarter 2005 Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 9, 2005) - Find Energy Ltd. (TSX:FE) ("Find" or the "Company") is pleased to announce its financial and operational results for the nine months ended September 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 nine-month periods ended September 30, 2005.

Find Energy achieved record cash flow and profitability during the third quarter of 2005.

The Pembina project progressed well and yielded impressive drilling results, a process that is continuing in Q4. Construction of the Find-operated natural gas plant is well underway and start-up is scheduled for mid-January 2006. Activity during Q3 was highlighted by successful drilling and well completion operations. Anticipated reserve additions resulting from this work and the added efficiency of owning and operating Find's major facility are expected to add future value.

Also during Q3 Find undertook a flow-through share financing, selling 1,000,000 shares on August 18, 2005 at $7.60 per share. The proceeds from this financing, combined with those from the sale of the southeast Saskatchewan properties on June 21, 2005, provided funding for the Company's very active capital program.

Q3 2005 Q2 2005 % Change
Financial Results
Revenue ($000) 16,248 15,051 8
Cash flow ($000) 10,183 8,370 22
Per share ($) 0.30 0.25 20
Net income ($000) 3,717 2,117 76
Per share ($) 0.11 0.06 83
Cash flow netback ($/boe) 36.25 26.22 38
Royalties ($/boe) 13.92 11.06 26
Operating expenses ($/boe) 6.95 7.62 (9)
General and administrative costs ($/boe) 0.47 1.20 (61)
Capital expenditures ($000) 27,217 8,424 223
Debt plus working capital
deficiency ($000) 14,528 1,978 634
Shares outstanding (000) 33,898 33,366 2

Production Volumes
Natural gas (mcf/day) 11,588 11,233 3
Oil and NGL (bbls/day) 1,122 1,636 (31)
Total (boe/day) 3,053 3,508 (13)

Production and Operations


Production during the nine months ended September 30, 2005 averaged 3,205 boe per day, up by 42 percent from 2,261 boe per day achieved in the same period in 2004.

Production during Q3 averaged 3,053 boe per day, comprised of 11.6 mmcf per day of natural gas and 1,122 bbls per day of oil and natural gas liquids. Find's combined production was 13 percent lower than in the previous quarter. In Q2 production was 3,508 boe per day, which was made up of 11.2 mmcf per day of natural gas and 1,636 bbls per day of oil and NGL. The reduction is due to the sale in late Q2 of Find's southeast Saskatchewan properties, which were producing 580 boe per day.

At present, Find is producing approximately 3,300 boe per day, comprised of 12.6 mmcf per day of natural gas and 1,210 bbls per day of oil and NGL. The increase in production is attributable to Find's successful drilling. Production additions have been temporarily restricted by the lack of natural gas processing capacity in the Pembina area. This constraint is expected to be alleviated when the Find-operated natural gas plant commences operation in January 2006.


During the nine months ended September 30, 2005, Find drilled 37 (25.2 net) wells. Of these, 31 (21.4 net) were natural gas wells, three (1.8 net) were oil wells and three (2.0 net) were dry holes, resulting in a drilling success rate of 92 percent.

During Q3, Find drilled 17 wells (12.4 net) resulting in 14 (10.6 net) natural gas wells and three (1.8 net) oil wells, yielding a success rate of 100 percent. Fourteen (10.6 net) of Find's Q3 wells were drilled in the Pembina area.

Pembina Natural Gas Plant and Development Program:

In July 2005, Find received authorization to construct a 30 mmcf per day natural gas processing plant, estimated to cost $18.0 million, in the Pembina area. Since that time the plant site has been prepared and construction has commenced in the field and at the fabrication centres. In order to expedite operations in the Pembina area, a 100-person camp has been established to house and feed personnel associated with all of the Company's activity. The plant project is on-track for the facility to commence processing by mid-January 2006. Find anticipates that the plant should achieve its 30 mmcf per day capacity in February. Find will operate the plant and hold an 85 percent ownership interest, providing proprietary access to 25.5 mmcf per day of through-put capacity.

Currently natural gas produced at Pembina is processed on a best-efforts basis by a third party at a facility built in 1997. Gathering and processing fees are $0.75 per mcf. This plant is operating at maximum capacity and is unable to take any greater daily volume from Find's wells. Find expects to operate its own facility and gas gathering system for approximately $0.30 per mcf. The difference will improve corporate netbacks and profitability.

At present, Find is producing approximately 11.7 (6.6 net) mmcf per day of natural gas and 880 (550 net) bbls per day of oil and NGL from 16 (9.6 net) wells at Pembina. Twenty-one (14.7 net) wells are not producing because of the natural gas processing constraints. The new natural gas processing facility will eliminate these constraints. Find estimates that the combined potential of these wells (so called "behind-pipe" production) is approximately 2,790 (1,930 net) boe per day, which is made up of 14.0 (9.7 net) mmcf per day of natural gas and 460 (315 net) bbls per day of oil and NGL.

The Pembina facility will be able to convert natural gas condensate to "frac oil". Frac oil is a product consumed in well completion operations. Frac oil currently sells at a premium of about 50 percent to the value of the natural gas condensate from which it is made. At current prices, the frac oil would generate approximately $5 million more per year for Find than selling the same volume as condensate. As well, producing its own frac oil will ensure availability for Find-operated well completions.

During Q3 Find was notified that its application before the Alberta Energy and Utilities Board (EUB) at Pembina, permitting two gas wells per section in the lower Mannville and Jurassic formations, had been approved. This approval is significant because it recognizes the need and opportunity to drill additional wells between known natural gas producers to effectively drain these reservoirs.

Currently there are three drilling rigs working for Find at Pembina. Sixteen (11.9 net) wells are scheduled to be drilled in the fourth quarter of which five (3.8 net) have been drilled to date, all successfully. Along with the drilling rigs, two completion rigs and well testing units are working steadily to prepare new wells for production operations. Well site facilities are being built and pipeline and gas gathering activity is underway.

Exploration activity is underway on the northern portion of Find's acreage at Pembina, where the Company holds exploration rights to the Nisku Formation underlying 17 sections of land. A 3-D seismic survey will be shot before year-end to assist in assessing the potential of these lands for drilling. Recent oil and natural gas discoveries and record land sale prices have been experienced within three miles of Find's lands. Over the past two years the Nisku play at Pembina has established itself as one of the most successful and sought-after in the Western Canada Sedimentary Basin.


Revenue from the Sale of Oil and Natural Gas:

Despite lower production volume, revenue in Q3 increased to $16.2 million from $15.1 million in the three months ended June 30, 2005. During the quarter Find received an average price of $9.60 per mcf of natural gas and $58.25 per bbl of oil and NGL.

Operating Costs:

Find reduced its unit operating costs to $6.95 per boe of production, a decline of 9 percent from Q2, when operating costs averaged $7.62 per boe. When the Pembina gas plant is fully operational, Find estimates that average corporate operating costs will be reduced by approximately $2.00 per boe from the current rate.

Cash Flow:

Cash flow of $10.2 million in Q3 was 22 percent greater than the previous quarter's $8.4 million, due almost entirely to improved prices for oil and natural gas. Cash flow per share was $0.30 per share in the third quarter compared with $0.25 per share in Q2. Find's average cash flow netback improved to $36.25 per boe of production, 38 percent greater than the $26.22 per boe achieved in Q2.

Net Income:

During Q3 Find generated net income of $3.7 million, or $0.11 per share, compared to $2.1 million, or $0.06 per share, in Q2.

Capital Expenditures:

In Q3, Find invested $27.2 million in capital expenditures, of which $22.8 million was directed toward drilling, completing, equipping and tying-in of new wells. To date in 2005 the Company has incurred $52.2 million in capital expenditures, less the proceeds of the southeast Saskatchewan sale, for a net amount to date of $24.2 million. Combined capital expenditures for all of 2005 are currently estimated at approximately $70 million net.

Bank Debt and Working Capital:

Find's total debt increased to $14.5 million at the end of Q3 from $2.0 million at the end of Q2. While Find's total debt increased by 634 percent quarter-over-quarter, the Company is not heavily indebted relative to its overall borrowing capacity or cash flow forecasts. Find has a $50 million revolving loan facility, bearing interest at the lender's prime rate.


The value of Find's efforts over the past several months is about to be realized. The drilling at Pembina has been very successful and we look forward to production without facility constraints commencing in January 2006.


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.



This management's discussion and analysis ("MD&A") dated November 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 and on the Company's website at

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 9M", "2005 Q3", "2005 Q2" and "2004 9M" refer to the nine months ended September 30, 2005, the three months ended September 30, 2005, the three months ended June 30, 2005 and the nine months ended September 30, 2004.

2005 2005 2005 2004
9M Avg. Q3 Avg. Q2 Avg. 9M Avg.
Natural Gas (mcf/day) 10,463 11,588 11,233 5,481
Oil and NGLs (bbls/day) 1,461 1,122 1,636 1,347
Total (boe/day) 3,205 3,053 3,508 2,261

On a total production basis, third quarter production was 13 percent lower than the second quarter. This was due to the sale of the southeast Saskatchewan properties which closed on June 21, 2005.

Natural gas production was three percent higher in the third quarter as compared to the second. Although Find drilled a total of 14 successful gas wells in the quarter, very little of this gas was brought on production. This was due to facility constraints in the Pembina West area, where the main gas processing plant was full for most of the quarter. Construction on Find's 30 Mmcfd gas plant is proceeding on schedule and gas should be flowing by early in the first quarter of 2006.

Crude oil and natural gas liquids production was 31 percent lower in the third quarter than the second. The southeast Saskatchewan properties contributed a total of 492 bopd of oil production to the second quarter average. New oil production at Pembina West was offset by natural declines in the Company's other oil properties.

For the nine months ended September 30, 2005, average daily production was 42 percent higher than the average daily production for the same nine-month period in 2004.

Product Pricing
2005 2005 2005 2004
Natural Gas ($/mcf) 9M Q3 Q2 9M
Price before hedging 8.27 9.60 7.63 6.91
Hedging gain (loss) - - - 0.01
Net price 8.27 9.60 7.63 6.92
AECO daily index 7.84 9.30 7.36 6.53
Nymex (US$/mcf) 7.72 9.72 6.95 5.83

Find's realized gas price jumped by $1.97 per mcf in the third quarter, an increase of 26 percent over the $7.63 per mcf received in the second quarter. Prices at the AECO storage hub followed suit, increasing by 26 percent in the third quarter over the second. For the nine-month period, Find's realized gas price of $8.27 per mcf was 20 percent higher than the $6.91 received for the first nine months of 2004.

Natural gas prices were certainly helped by the large increase in crude oil prices during the quarter. Strong natural gas demand for electricity generation due to an unusually hot summer led to the rate of storage refill in the United States being lower than most market participants had expected. This has caused storage inventories to be below the three year average storage level for this point in the injection cycle and only slightly above the five year average. The impact of Hurricane Katrina on Gulf of Mexico production platforms has also caused some supply worries that has translated into higher prices.

Find had no natural gas price hedges in place in the first nine months of the year and has not entered into any subsequent to the end of the third quarter.

2005 2005 2005 2004
Oil and Natural Gas Liquids ($/bbl) 9M Q3 Q2 9M
Price before hedging 51.04 58.25 48.71 43.21
Hedging gain (loss) (0.41) - - (2.66)
Net price 50.63 58.25 48.71 40.55
WTI (US$/bbl) 55.25 63.01 53.03 39.18
Edmonton light ($/bbl) 68.55 77.21 66.42 51.25
CDN$/US$ 0.8172 0.8325 0.804 0.7532

Find's realized oil and natural gas liquids price was $9.54 per bbl or 20 percent higher than the $48.71 per bbl the Company received for its oil and natural gas liquids in the second quarter. Both West Texas Intermediate ("WTI") prices and Edmonton Light posting were up by similar percentages in the quarter.

Crude oil raced to record highs as WTI averaged $63.01 per bbl in the third quarter as compared to $53.03 in the second quarter. Strong demand in Asian economies as well as in the United States has caused most of the world's excess supply capacity to be reduced to near zero levels. Damage caused by Hurricane Katrina to Gulf of Mexico production platforms added more supply concerns to the market and drove prices briefly to the $70 WTI level. Although recent prices have come off the high point, forward prices at the time of this MD&A are still above $60 WTI.

Income Statement
2005 2005 2005 2004
Revenue 9M Q3 Q2 9M
Oil & natural gas sales,
before hedging ($000) 43,983 16,248 15,051 26,324
Per boe ($) 50.27 57.84 47.14 42.49
Hedging loss ($000) 468 - - 969
Per boe ($) 0.53 - - 1.56

Revenue Reconciliation
Revenue for the three months ended June 30, 2005 ($000) 15,051
Increase in commodity prices ($000) 3,573
Increase (decrease) in production volumes ($000) (2,376)
Revenue for the three months ended September 30, 2005 ($000) 16,248

2005 2005 2005 2004
Royalties 9M Q3 Q2 9M
Total Royalties ($000) 10,187 3,909 3,532 5,534
% of revenue before hedging 23.2 24.1 23.5 21.0
Per boe ($) 11.64 13.92 11.06 8.93

Royalty rates continued to climb during the quarter. Two high productivity horizontal wells in the Hazlet unit came off low royalty status during the quarter. Higher commodity prices increase the effective crown royalty rate.

Pembina West gas production is classified as "new gas" and therefore attracts the highest crown royalty rate. As a greater proportion of the Company's production comes from Pembina West, in the future royalty rates will rise.

2005 2005 2005 2004
Operating Expenses 9M Q3 Q2 9M
Total lease operating ($000) 6,757 1,954 2,432 6,157
Per boe ($) 7.72 6.95 7.62 9.94

Lease operating costs continued to decline, falling by nine percent to $6.95 per boe as compared to the second quarter of 2005. The sale of the southeast Saskatchewan properties closed just before the end of the second quarter and was characterized by higher operating costs so consequently the third quarter reflects the full impact of this disposition. Future operating cost reductions are expected in the first quarter of 2006 when the Pembina West gas plant becomes fully operational.

For the nine months ended September 30, 2005, lease operating expenses were $7.72 per boe or 22 percent lower than lease operating expenses for the same period a year earlier.

2005 2005 2005 2004
General & Administrative ($000) 9M Q3 Q2 9M
Total G & A expense 3,404 1,058 1,343 3,132
Recoveries (1,330) (541) (380) (759)
Capitalized (1,286) (384) (581) (894)
Net 788 133 382 1,479
Per boe ($) 0.90 0.47 1.20 2.39

Total gross general and administrative costs declined by 21 percent in the third quarter when compared to the second quarter. This decrease is due to second quarter general and administrative expenses containing some one time charges for employee retention costs as well as corporate costs for year end statutory reporting and filings. Recoveries were much higher in the third quarter due to the increased level of capital expenditures as compared to the second quarter.

2005 2005 2005 2004
Interest Expense ($000) 9M Q3 Q2 9M
Total interest expense ($000) 354 21 216 539
Per boe ($) 0.40 0.08 0.68 0.87

Interest expense was down dramatically in the third quarter totalling only $21,000. This was due to the sale of the southeast Saskatchewan properties, which closed at the end of the second quarter and paid off the Company's bank indebtedness at that time. Further, the net proceeds from the flow-through share issue that closed in August were initially used to reduce bank indebtedness.

Near the end of the third quarter, the prime rate increased by a quarter of a point to 4.50 percent. Subsequent to the end of the quarter the prime rate increased by another 25 basis points.

2005 2005 2005 2004
Provision for Taxes ($000) 9M Q3 Q2 9M
Future income taxes 4,955 2,228 1,614 985
Current tax expense - - - -
Capital tax expense 407 76 190 473
Total tax expense 5,362 2,304 1,804 1,458

Capital tax expense was down in the third quarter as compared to the second due to the sale of the southeast Saskatchewan properties. Oil and gas properties in Saskatchewan are charged a capital tax based on revenue by the Saskatchewan government.

2005 2005 2005 2004
Stock-based Compensation ($000) 9M Q3 Q2 9M
Total stock-based compensation 1,129 395 390 751
Capitalized (423) (138) (158) (239)
Net 706 257 232 512
Per boe ($) 0.81 0.92 0.73 0.83

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 third quarter, there was only a slight change in the expensed amount.

Depletion, Depreciation and 2005 2005 2005 2004
Accretion 9M Q3 Q2 9M
Total DD&A ($000) 12,167 3,981 4,408 7,828
Per boe ($) 13.91 14.17 13.81 12.64

Depletion, depreciation and accretion expense was virtually unchanged on a boe basis in the third quarter when compared to the second. Included in the third quarter depletion calculation is approximately $4.6 MM in costs related to the Pembina West gas plant to which no reserves have been assigned.

2005 2005 2005 2004
Net Income ($000) 9M Q3 Q2 9M
Net income 7,227 3,717 2,117 1,945
Per boe ($) 8.26 13.23 6.63 3.14
Per share ($) 0.22 0.11 0.06 0.07
Diluted per share ($) 0.21 0.11 0.06 0.07
Weighted average shares
outstanding (000) 33,532 33,498 33,558 27,462

Net income was up strongly in the third quarter, growing by 76 percent to $3.7 million as compared to the $2.1 million recorded in the second quarter of 2005. Net income per boe grew even more, doubling to $13.23 in the third quarter.

For the nine months ended September 30, 2005, net income was 272 percent greater than the net income recorded in the same period of 2004.

2005 Q3 2005 Q2
$000 $/boe $000 $/boe
Revenue, from oil and gas sales
and other income 16,276 57.94 15,122 47.37

Royalties 3,909 13.92 3,532 11.06
Operating Expenses 1,954 6.95 2,432 7.62
General and administrative 133 0.47 382 1.20
Interest 21 0.08 216 0.68
Capital taxes 76 0.27 190 0.59
6,093 21.69 6,752 21.15

Cash flow from operations 10,183 36.25 8,370 26.22

Depletion, depreciation &
accretion 3,981 14.17 4,408 13.81
Stock-based compensation 257 0.92 232 0.73
Future taxes 2,228 7.93 1,614 5.05
Net income 3,717 13.23 2,116 6.63

Liquidity and Capital Resources
2005 2005 2005 2004
Cash Flow from Operations 9M Q3 Q2 9M
Cash flow from operations ($000) 25,427 10,183 8,370 11,270
Cash flow from operations,
per basic share ($) 0.76 0.30 0.25 0.41
Cash flow from operation,
per diluted share ($) 0.73 0.29 0.25 0.41
Cash flow netback, per boe ($) 29.06 36.25 26.22 18.19
Cash flow as a percentage of
revenue 57.7% 62.6% 55.6% 42.8%
Weighted average shares
outstanding (000) 33,532 33,498 33,558 27,462

Despite a 13 percent drop in production volumes quarter over quarter, cash flow was up significantly in the third quarter of 2005 when compared to the second quarter. Total cash flow grew by 22 percent to $10.2 million; on a per share basis it grew by 20 percent to $0.30.

This growth in cash flow was driven by increased average commodity prices, as they were up by 23 percent quarter over quarter. Of particular note is that after excluding royalties, other cash costs declined by 23 percent. While fourth quarter cash costs are expected to be about the same as the third quarter, Find expects reductions to lease operating expenses to occur in the first quarter of 2006 when the Pembina West gas plant becomes fully operational.

Capital Expenditures ($000) 2005 Q3 2005 Q2 2005 Q1
Land and seismic 4,036 (27,867) 820
Drilling and completions 15,821 6,107 11,742
Well equipment and facilities 6,976 1,258 5,301
26,833 (20,502) 17,863
Capitalized G & A 384 580 322
Total capital expenditures 27,217 (19,922) 18,185

Capital Expenditures by Area
(Nine Months ended September 30, 2005)

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

West Central 4,854 31,132 11,045 47,031
East Central (13) 2,413 673 3,073
SE Saskatchewan (28,362) 125 276 (27,961)
Other 510 - 1,541 2,051
(23,011) 33,670 13,535 24,194

Equity Financing

On August 18, the Company closed its previously announced bought-deal private placement of flow-through common shares. A total of 1,000,000 shares were sold at an issue price of $7.60 per share. Net proceeds from the issue were approximately $7.1 million. Find intends to use the equity proceeds to fund seismic programs and exploration drilling, primarily in the Pembina West area.

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.

During the third quarter, Find purchased 467,600 shares at an average cost including commission of $5.50 per share. Since the inception of the normal course issuer bid, Find has purchased and cancelled a total of 710,400 shares at an average cost of $5.10 per share.

Note Receivable

In late 2004, Find sold minor Saskatchewan properties. Proceeds received included a non-interest bearing promissory note. The note was to be repaid in equal monthly installments over a period of one year. The final payment on the note was received during the third quarter.

Wells Drilled by Area
(Nine Months ended September 30, 2005)

Area Gas Oil D & A Total Success
Gross Net Gross Net Gross Net Gross Net Rate
West Central 30 20.4 3 1.8 3 2.0 36 24.2 92%
East Central 1 1.0 - - - - 1 1.0 100%
SE Sask - - - - - - - - -
Other - - - - - - - - -
31 21.4 3 1.8 3 2.0 37 25.2 92%

During the quarter, the Company drilled a total of 17 wells (12.4 net), resulting in 14 gas wells (10.6 net) and 3 oil wells (1.8 net). All of the drilling in the third quarter took place at Find's West Central area. Within the West Central area, a total of 14 wells (10.6 net) were drilled at Pembina West, resulting in 11 gas wells (8.8 net) and 3 oil wells (1.8 net). A total of $21.3 million was spent on capital expenditures at Pembina West during the third quarter.


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 has little impact. The following table illustrates the sensitivity of Find's cash flow to changes in natural gas prices, oil prices, CDN dollar and to growth in production volumes.

Annual Cash Flow Cash Flow
($000) per Share
100 Boed of production 1,644 $0.05
Crude oil - WTI price change of
$1.00 US/bbl 557 $0.02
Natural gas - AECO price change
of $0.25/mcf 1,607 $0.05
CDN$ - change of $0.01 US 472 $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 2004 2003
Q3 Q2 Q1 Q4
Petroleum & natural gas sales 8,814 9,805 7,705 6,125
Income (loss) for the quarter 1,398 877 (330) (520)
Income (loss) per share -
basic & diluted 0.05 0.03 (0.01) (0.02)

2005 2005 2005 2004
Q3 Q2 Q1 Q4
Petroleum & natural gas sales 16,248 15,051 12,684 10,029
Income for the quarter 3,717 2,117 1,393 960
Income per share - basic 0.11 0.06 0.04 0.03
Income per share - diluted 0.11 0.06 0.04 0.03

Estimated Tax Pools ($million)
September 30, 2005
Canadian oil & gas property expense -
Canadian development expense 33.4
Canadian exploration expense 14.5
Tangibles 20.3
Non-capital losses 7.7
Financing expenses 2.5

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 nine months 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 third 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 September 30, 2005, Find had a ceiling test cushion of approximately $52.1 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 September 30, 2005, Find excluded $15.3 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 recorded 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 45 - 50 percent is an appropriate volatility rate for Find. Actual volatility could be more or less than this range which could have a material impact on net income.

Share Capital

As at November 2, 2005, the Corporation has 33,898,376 shares and 3,420,000 stock options outstanding.

Consolidated Financial Statements of


September 30, 2005

Consolidated Balance Sheets
September 30, 2005 and December 31, 2004

September December
30, 2005 31, 2004
$ $
(unaudited) (audited)


Cash and cash equivalents 200 200
Accounts receivable 10,859,641 11,528,233
Note receivable (Note 2) - 2,212,500
Prepaid expenses 442,806 196,374
Foreign exchange contracts (Note 10(a)) - 372,060
11,302,647 14,309,367

Deposits and other (Note 3) 347,312 230,761
Property and equipment (Note 4) 115,491,837 101,514,146
127,141,796 116,054,274


Accounts payable and accrued liabilities 24,529,291 22,785,505
Income taxes payable 32,922 26,400
Bank indebtedness (Note 6) 1,268,294 9,153,618
25,830,507 31,965,523
Asset retirement obligations (Note 5) 3,503,664 3,263,675
Future income taxes 10,738,743 5,958,016


Share capital (Note 8) 78,069,688 72,076,343
Contributed surplus 2,387,499 1,343,471
Retained earnings 6,611,695 1,447,246
87,068,882 74,867,060
127,141,796 116,054,274
Commitments and contingencies (Note 10)

The accompanying notes are an integral part of these financial


Consolidated Statements of Operations and Retained Earnings
For the nine month period ended September 30

Three Months Ended Nine Months Ended
September 30 September 30
2005 2004 2005 2004
$ $ $ $
Petroleum and natural
gas sales 16,247,525 8,671,364 43,515,354 25,354,600
Royalties 3,909,039 1,694,172 10,187,108 5,533,547
12,338,486 6,977,192 33,328,246 19,821,053
Interest and other 28,190 812 100,000 96,959
Realized loss on
financial instruments
(Note 10(a)) - - (67,685) -
12,366,676 6,978,004 33,360,561 19,918,012

Operating 1,953,594 1,753,358 6,757,319 6,156,847
General and
administrative 132,680 309,611 788,161 1,478,519
Interest 21,365 153,672 353,650 539,340
Depletion, depreciation
and accretion 3,980,521 2,375,305 12,166,589 7,828,211
Stock-based compensation
(Note 8(e)) 257,233 184,066 705,909 512,390
6,345,393 4,776,012 20,771,628 16,515,307
Income before taxes 6,021,283 2,201,992 12,588,933 3,402,705

Provision for taxes
(Note 7)
Capital 76,003 124,288 406,805 473,225
Future 2,228,022 679,662 4,955,418 984,336
2,304,025 803,950 5,362,223 1,457,561
Income for the period 3,717,258 1,398,042 7,226,710 1,945,144
beginning of the
period 4,461,726 (910,433) 1,447,246 (1,457,535)
Excess of cost of
shares acquired over
stated value
(Note 8(d)) (1,567,289) - (2,062,261) -
Retained earnings,
end of period 6,611,695 487,609 6,611,695 487,609
Income per share
Basic 0.11 0.05 0.22 0.07
Diluted 0.11 0.05 0.21 0.07
Weighted average
number of shares
- basic (Note 9) 33,497,573 29,442,110 33,532,381 27,461,752
Total number of shares
outstanding, end of
period (Note 8(b)) 33,898,376 29,442,110 33,898,376 29,442,110

The accompanying notes are an integral part of these financial


Consolidated Statements of Cash Flows
For the nine month period ended September 30

Three Months Ended Nine Months Ended
September 30 September 30
2005 2004 2005 2004
$ $ $ $


Income for the period 3,717,258 1,398,042 7,226,710 1,945,144
Adjustments for:
Unrealized gain on
financial instruments
(Note 10(a)) - - 372,060 -
and accretion 3,980,521 2,375,305 12,166,589 7,828,211
compensation 257,233 184,066 705,909 512,390
Future income taxes 2,228,022 679,662 4,955,418 984,336
10,183,034 4,637,075 25,426,686 11,270,081
Changes in non-cash
working capital (312,447) 174,713 1,322,227 (1,059,879)
9,870,587 4,811,788 26,748,913 10,210,202
Issue of shares, net
of share issue costs 7,083,255 (3,102) 7,262,286 11,245,478
Bank indebtedness (7,302,755) 180,931 (7,885,324) 2,426,918
Redemption of share
capital - normal
course issuer bid (2,573,769) - (3,591,226) -
Changes in non-cash
working capital - - (178,665) -
(2,793,269) 177,829 (4,392,929) 13,672,396
Property and
equipment (27,217,132) (8,505,604) (53,988,507)(24,770,811)
Other deposits (24,538) 363 (116,550) (6,850)
Proceeds on sale of
properties - - 28,507,666 -
Changes in non-cash
working capital 6,610,352 3,494,608 3,241,407 871,885
(20,631,318) (5,010,633) (22,355,984)(23,905,776)
Net decrease in cash
and cash equivalents (13,554,000) (21,016) - (23,178)
Cash and cash
beginning of period 13,554,200 21,216 200 23,378
Cash and cash
end of period 200 200 200 200
Taxes paid during
the period 133,904 (167,957) 470,318 437,304
Interest paid during
the period 6,943 147,129 307,959 497,646

The accompanying notes are an integral part of these financial

Notes to the Consolidated Financial Statements
September 30, 2005


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.


On October 1, 2004, the Corporation sold certain Saskatchewan properties. Proceeds received include a promissory note. As at September 30, 2005, the note was paid in full.


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


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

Petroleum and natural gas
properties and equipment 141,883,030 26,446,245 115,436,785

Furniture and equipment 111,363 56,311 55,052
-------------- ------------- --------------
141,994,393 26,502,556 115,491,837
-------------- ------------- --------------
-------------- ------------- --------------

Unproved properties and proprietary seismic data of $15,255,300 have been excluded from costs subject to depletion. During the first nine months of 2005, the Corporation capitalized $1,709,700 (2004 - $1,133,000) of general and administrative expenditures and stock-based compensation related to exploration and development activities.


The change in asset retirement obligation for the year ended December 31, 2004 and nine month periods ended September 30, 2005 and 2004 are as follows:

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

Asset retirement obligation,
beginning of period 3,263,675 3,616,855 3,616,855
Liabilities incurred 642,105 174,618 481,500
Liabilities settled (554,397) - (1,070,067)
Accretion expense 152,281 189,884 235,387
Revisions in estimated cash
flows - - -
-------------- ------------- --------------
Asset retirement obligation,
end of period 3,503,664 3,981,357 3,263,675
-------------- ------------- --------------
-------------- ------------- --------------

The total estimated, undiscounted cash flows required to settle the obligations at September 30, 2005 without including salvage, is $6,742,531 (September 30, 2004 - $6,728,117 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 September 30, 2004 - 7.0%). The Corporation expects these obligations to be settled, on average in 12.5 years, the majority of which is expected to be incurred between 2008 and 2025.


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, guaranteed notes 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 September 30, 2005 is comprised of the following:

Revolving Operating Demand Loan at prime plus 0% $ 472,976
Guaranteed Notes -
Letter of Guarantee 795,318
$ 1,268,294

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.


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


(a) Authorized

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

(b) Issued common shares

Nine months ended Year ended
September 30, 2005 December 31, 2004
------------------------ -----------------------
Number of Number of
Shares Amount $ Shares Amount $
------------------------ -----------------------
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)) (710,400) (1,528,964) - -
Issued for cash on
exercise of warrants - - 947 5,682
Issued for cash
pursuant to private
placements (Note 8(c)) 1,000,000 7,600,000 7,600,000 28,065,000
Future income taxes
on expenditures
renounced for
flow-through shares - - - (4,972,058)
------------------------ -----------------------
33,898,376 78,411,376 33,542,110 73,196,689
Share issue costs,
(net of tax of
$174,691, 2004
- $572,786) - (341,688) - (1,120,346)
------------------------ -----------------------
Balance, end of period 33,898,376 78,069,688 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.

On August 18, 2005, the Corporation completed a private placement of 1,000,000 flow-through common shares at a price of $7.60. Transaction costs were $517,000 including fees paid to underwriters. The future income tax cost of approximately $2,571,100 associated with renouncing the expenditures will be recorded on the date of renunciation.

(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 710,400 common shares were purchased up to September 30, 2005 at a cost of $3,591,225. The excess of the cost to repurchase over the stated value of the shares of $2,062,261 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 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 September 30, 2005 is as follows:

Weighted Remaining
Number Average Contractual
Of Exercise Life
Continuity of stock options Shares Price (Years)
----------- -------- ------------
Outstanding, December 31, 2004 3,259,000 $ 2.81 4.1
Granted during the period 362,500 3.84 4.6
Exercised during the period (66,666) 2.68 -
Cancelled during the period (134,834) 2.88 3.5
----------- -------- ------------
Outstanding, September 30, 2005 3,420,000 $ 2.92 3.5
----------- -------- ------------
----------- -------- ------------

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

Options Outstanding Exercisable Options
----------------------------------- ----------------------
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 3.2 $2.66 873,860 $2.66
$2.81 to $3.30 353,000 4.4 3.02 31,833 2.90
$3.31 to $3.80 440,400 4.2 3.66 - -
$3.81 to $4.30 15,000 4.7 4.20 - -
$5.51 to $6.00 90,000 4.9 6.00 - -
3,420,000 3.5 $2.92 905,693 $2.67
----------------------------------- ----------------------
----------------------------------- ----------------------

Compensation expense recognized for the nine months ended September 30, 2005 related to options granted in prior years was $1,037,121, of which $662,766 was charged to income and $374,355 was capitalized.

The fair value of stock options granted during the nine months ended September 30, 2005 was estimated using the Black-Scholes option pricing model and with the following assumptions: expected volatility (45% 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 $2.63 per share.

Compensation expense recognized for the nine months ended September 30, 2005 related to options granted in 2005 was $92,239, of which $43,143 was charged to income and $49,096 was capitalized.


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

Three Months Ended Nine Months Ended
September 30 September 30
----------------------- -----------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Basic 33,497,573 29,442,110 33,532,381 27,461,752
Diluted 34,687,077 29,608,334 34,721,885 27,627,976


(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 September 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 nine months is $304,375. At December 31, 2004, $372,060 of this was marked-to-market, with a net realized loss in the first nine 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 September 30, 2005, future minimum amounts payable on a fiscal year basis, excluding operating costs, are as follows:

2005 66,345
2006 184,658
2007 23,967
2008 8,594
2009 7,584
2010 1,896

(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.

Contact Information

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