ProspEx Announces 2010 Third Quarter Results, Success at Pembina and Adoption
of Shareholder Rights Plan

News provided by

Nov 15, 2010, 07:00 ET

(All amounts are in Canadian dollars, unless stated otherwise)

CALGARY, Nov. 15 /CNW/ - ProspEx Resources Ltd. ("ProspEx" or the "Company") announces its financial and operating results for the three and nine months ended September 30, 2010 and the adoption of a shareholder rights plan (the "Rights Plan").

"ProspEx is pleased to announce that our first horizontal well in the Pembina area of West Central Alberta tested at a rate of 19 million cubic feet per day at the conclusion of a 50 hour flow test," said John Rossall, President and Chief Executive Officer. "In addition, ongoing drilling success in Kakwa has increased current corporate production to approximately 3,400 barrels of oil equivalent per day, with substantial incremental production expected to come on stream by year end."

HIGHLIGHTS

ProspEx recently completed its first horizontal well at Pembina in West Central Alberta (100% working interest). This well targeted the liquids rich Falher formation, and produced at a final rate of 19 million cubic feet ("mmcf") per day at a flowing wellhead pressure of 1,887 pounds per square inch ("psi") at the conclusion of a 50 hour flow test.
ProspEx also resumed horizontal drilling activity in the Falher play at Kakwa in early July. Three Kakwa wells were drilled during the third quarter: the first well is now onstream at a gross raw gas rate of 11.8 mmcf per day, the second well recorded a final test rate of 6.6 mmcf per day, and the third well has been cased and is currently awaiting completion.
Production for the third quarter decreased to 2,685 barrels of oil equivalent ("boe") per day, compared to 3,086 boe per day in the second quarter of 2010. However, with the recent tie-in of the latest Kakwa well, current corporate production is estimated to be approximately 3,400 boe per day. In addition to this production, the Company has three (1.9 net) horizontal wells that have been drilled but are not yet on production, including the Pembina well.
Total capital expenditures were $7.7 million during the third quarter of 2010.
Third quarter cash flow (before changes in non-cash working capital items) was $3.3 million, compared to $2.0 million in the prior year's quarter, reflecting increases in production and commodity prices.
Total net debt (excluding the fair value of commodity contracts, the current loss on office sublease and associated future taxes) at September 30, 2010 was $28.1 million. Subsequent to quarter end, ProspEx completed an equity financing for net proceeds of approximately $5 million.

SHAREHOLDER RIGHTS PLAN

The board of directors of the Company (the "Board") has approved the adoption of the Rights Plan. The Rights Plan is effective immediately and will be submitted to the Company's shareholders for ratification at the next annual general meeting expected to be held in May 2011 (the "Ratification"). The Toronto Stock Exchange has conditionally accepted the Rights Plan for filing subject to the Ratification occurring within six months.

The Rights Plan is intended as a means to ensure the fair and equal treatment of shareholders in connection with a take-over bid for the outstanding voting common shares of the Company (the "Common Shares"). By encouraging an acquirer to make a bid that qualifies as a "Permitted Bid" or is on terms negotiated with the Board, the Rights Plan is intended to provide the Board sufficient time to explore and develop alternatives to enhance shareholder value. To qualify as a "Permitted Bid" under the Rights Plan, a take-over bid must, among other things, be made to all shareholders and remain open for acceptance for at least 60 days from the date of the bid.

At the close of business on November 12, 2010, one right was issued and attached to each of the outstanding Common Shares and one right will be attached to each Common Share issued after that date during the term of the Rights Plan. These rights will become exercisable only if a person (together with its associates, affiliates and joint actors) acquires 20% or more of the Common Shares other than pursuant to a Permitted Bid or certain other exempt transactions, or commences or announces an intention to commence a take-over bid that does not qualify as a Permitted Bid. In the event of any such acquisition, the rights entitle shareholders other than the acquiring person (and its associates, affiliates and joint actors) to purchase additional Common Shares at a significant discount to their market price.

The Company is not currently aware of any take-over bid which has been made or is contemplated and the Rights Plan is similar to plans adopted by other Canadian issuers and ratified by their shareholders. It is not intended to prevent a take-over of the Company, to entrench management or defer take-over bids that treat shareholders fairly.

The complete terms and conditions of the Rights Plan are set forth in a shareholder rights plan agreement between the Company and Olympia Trust Company, as rights agent, a copy of which may be obtained from the Company or from the SEDAR website (www.sedar.com).

OPERATIONAL REVIEW

Capital Program

Subsequent to quarter end, ProspEx drilled its first horizontal well (100% working interest) at Pembina in West Central Alberta. This well targeted the liquids rich Falher formation, and was ProspEx's first well in this new operating area. Following a multi-stage fracture stimulation, this well was produced up 4½" casing for a period of 50 hours, with a final rate of 19 mmcf per day at a flowing wellhead pressure of 1,887 psi. This well is expected to be on production in early December, 2010. ProspEx has identified seven additional 100% working interest locations on its existing lands in Pembina offsetting this well.

Total capital expenditures were $7.7 million during the third quarter of 2010. ProspEx's drilling activity continued to focus on horizontal drilling of liquids rich, Cretaceous age, natural gas targets. During the third quarter, the Company participated in three (1.5 net) horizontal wells targeting the Falher formation at Kakwa in the Deep Basin. The first of these wells at 13-8-64-4W6 (the "13-8 well") was brought on to production at the end of October at a gross raw gas rate of 11.8 mmcf per day. ProspEx has a 59% working interest in the 13-8 well.

The second well in this program, located at 13-16-64-4W6 (the "13-16 well") was drilled and confirmed the location of the eastern boundary of the pool inferred from the Company's seismic interpretation. The 13-16 well was tested at a final rate of 6.6 mmcf per day at a flowing wellhead pressure of 552 psi at the end of a 24 hour test. This well is expected to be on stream in December, 2010. ProspEx has a 59% working interest in the 13-16 well.

The third well of the Kakwa program, located at 2-30-64-4W6 (the "2-30 well") has been drilled and is currently awaiting completion. Completion of this well is scheduled for late November, 2010. The 2-30 well was drilled to a bottom hole location immediately north of ProspEx's 15-19-64-4W6 well (the "15-19 well"), which has produced for nine months with an average gross raw gas rate of 5.9 mmcf per day over the nine month period. ProspEx has a 30% working interest in the 2-30 well.

ProspEx currently has one additional Kakwa horizontal well scheduled to commence drilling prior to year end 2010. This well is intended to confirm the extension of the Falher trend to the south of the Company's existing wells. ProspEx has an inventory of 21 (10.5 net) undrilled horizontal well locations in Kakwa.

Production

Production (boe/d)	Q3 2010	Q2 2010	Q1 2010	Q4 2009	Q3 2009
West Central Alberta	930	925	1,030	1,280	1,289
Deep Basin	1,737	2,129	1,953	1,183	675
Other Areas	18	32	11	14	14
Total	2,685	3,086	2,994	2,477	1,978

Third quarter 2010 production averaged 2,685 boe per day. Production increased by 36% compared to the third quarter of 2009, but declined modestly compared to the second quarter of 2010, as no material new production was brought on stream during the quarter. However, with the new Kakwa 13-8 well coming on stream recently, current production is now estimated to be 3,400 boe per day. ProspEx has incremental production from the Pembina horizontal well discussed above, and incremental production from both the Kakwa 13-16 and 2-30 wells still to come on stream. In addition, approximately 500 boe per day of production from previously drilled Kakwa wells has been temporarily curtailed due to the high initial production rates from the 13-8 well. This curtailed production is expected to resume as the initial production rates from the 13-8 well subside.

In light of lower natural gas prices, the Company elected not to spend additional capital to maintain the pace of its capital spending program in the face of wet weather conditions. Accordingly, ProspEx now expects annual average production to be approximately 3,000 boe per day, down from the previous forecast of 3,100 to 3,300 boe per day. However, the Company believes that it is on track to meet its previously issued 4,000 boe per day production guidance for late December.

Guidance regarding production may constitute a "financial outlook" as contemplated by National Instrument 51-102 of the Canadian Securities Administrators entitled Disclosure Obligations. The purpose of such guidance is to forecast the anticipated production for the Company as at the end of December 2010 and for the full year 2010 and such information may not be appropriate for other purposes.

ProspEx has three horizontal wells in Kakwa with longer term production histories. The Company's first horizontal well (the "2-33 well") has been on stream for 12 months, and has produced an estimated 1.9 billion cubic feet ("bcf") of raw gas over this time period, equivalent to a production rate of 5.1 mmcf per day. ProspEx's second well, the 15-19 well has produced for nine months and has a production profile similar to the 2-33 well, with an average raw gas rate of 5.9 mmcf per day over the nine month period. The third well (the "1-6 well") has produced at an average rate of 2.7 mmcf per day over an eight month period.

Based on well test data and initial production rates, ProspEx believes that the production profile of the new 13-8 well will resemble that of the 2-33 and 15-19 wells. The 13-16 well was intended to evaluate the eastern boundary of the pool, and as such is interpreted to have encountered a thinner reservoir as it approached the edge of the pool, resulting in lower expected productivity than wells drilled in the centre of the pool. Based on test rates, the Company believes the 13-16 production profile will resemble the 1-6 well. As the 2-30 well has yet to be completed, it is difficult to estimate the potential productivity of this well. However, ProspEx notes that this well was drilled to a bottom hole location immediately north of the 15-19 well.

The Kakwa Falher play continues to generate very strong results. The Company believes that the high production rates of liquids rich gas generate robust economics, even at lower gas prices. Further information with respect to these wells is available in the Company's investor presentation that can be accessed on ProspEx's website at www.psx.ca.

Financial

Third quarter cash flow (before changes in non-cash working capital items) was $3.3 million, compared to $3.5 million in the second quarter, as declines in production were offset by lower royalties and operating costs. Total capital spending was $7.7 million.

Total net debt (excluding the fair value of commodity contracts, the current loss on office sublease and associated future taxes) at September 30, 2010 was $28.1 million which is equivalent to 1.9 years net debt to annualized trailing cash flow. Subsequent to quarter end, ProspEx completed an equity financing for net proceeds of approximately $5 million.

Reader's Advisory

ProspEx is a Calgary based junior oil and gas company focused on exploration for natural gas in the Western Canadian Sedimentary Basin.

Certain information contained in this press release constitutes forward-looking information or statements including, without limitation, information and statements respecting: anticipated production profiles and economics of wells, anticipated cash flow, capital expenditures, production forecasts, production additions and deletions, reserves and resources additions and deletions, additions to and deletions from the Company's historical and future capital programs, acquisitions or dispositions, operating expenses, G&A, royalties, expected timing of the tie-in of wells, expected timing of the receipt of regulatory approvals and expected timing of the completion of facilities projects.

Statements relating to "reserves" and "resources" are forward-looking information as they involve the implied assessment, based on certain estimates and assumptions that, among others, the reserves and resources described exist in the quantities predicted or estimated.

Forward-looking information and statements are often, but not always, identified by the use of words such as "anticipate", "seek", "believe", "expect", "hope", "plan", "intend", "forecast", "target", "project", "guidance", "may", "might", "will", "should", "could", "estimate", "predict" or similar words or expressions suggesting future outcomes or language suggesting an outlook. By their very nature, forward-looking information and statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking information and statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to vary materially from the forward-looking information or statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs; capital expenditures; the imprecision of reserve and resource estimates and estimates of recoverable quantities of oil, natural gas and liquids; the Company's ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions or dispositions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax and royalty laws; the Company's ability to access external sources of debt and equity capital; and the Company's ability to obtain equipment in a timely manner to carry out development activities. Further information regarding these factors may be found under the headings "Description of the Business - Risk Factors Relating to Our Business" and "Industry Conditions" in the Company's most recent Annual Information Form, under the heading "Operational and Other Business Risks" in the Company's Management's Discussion and Analysis for the year ended December 31, 2009, and in the Company's most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases available under the Company's profile on SEDAR (www.sedar.com). Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to the Company, investors and others should also carefully consider information set forth in the section "Forward-Looking Information" of the Company's most recent Annual Information Form respecting the assumptions upon which the Company bases certain forward-looking information and the uncertainties inherent in such assumptions.

The Company does not assume responsibility for the accuracy and completeness of the forward-looking information or statements and such information and statements should not be taken as guarantees of future outcomes. Subject to applicable securities laws, the Company does not undertake any obligation to revise these forward-looking information or statements to reflect subsequent events or circumstances. Furthermore, the forward-looking information contained in this press release are made as of the date of this document and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable law. The forward-looking information and statements contained in this press release are expressly qualified by this cautionary statement.

For the purposes of this press release, boe has been calculated on the basis of six thousand cubic feet of gas to one barrel of oil. The term boe may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

"Operating netbacks" are calculated by subtracting transportation costs, royalties and operating costs from the average price received during the period.

"Total net debt" is calculated by adding long-term debt less working capital (or plus working capital deficiency), excluding fair value of commodity contracts, current loss on sublease and associated future tax assets (liabilities).

ProspEx Resources Ltd. Consolidated Highlights For the periods ended
(unaudited)		Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
FINANCIAL ($000's)
Oil and gas revenue		8,007	5,023	28,097	25,158
Net loss		(1,626)	(3,082)	(1,618)	(9,206)
Cash flow ⁽¹⁾		3,331	1,969	12,070	10,165
Total assets		162,952	160,129	162,952	160,129
Total net debt ⁽²⁾		28,123	27,841	28,123	27,841

Net loss per share ($ per share)
	Basic	(0.03)	(0.05)	(0.03)	(0.16)
	Diluted	(0.03)	(0.05)	(0.03)	(0.16)
Cash flow per share ($ per share) ⁽¹⁾
	Basic	0.06	0.03	0.21	0.18
	Diluted	0.06	0.03	0.21	0.18
Weighted average common shares (000's)
	Basic	57,388	57,385	57,386	57,385
	Diluted	57,388	57,385	57,386	57,385
PRODUCTION VOLUMES
	Natural gas (mcf/d)	13,477	8,906	14,250	13,585
	Natural gas liquids (bbls/d)	419	456	521	637
	Oil (bbls/d)	20	37	25	51
	Total (boe/d)	2,685	1,978	2,921	2,951

SALES PRICES
	Natural gas ($/mcf)	4.74	3.70	5.05	4.83
	Natural gas liquids ($/bbl)	51.60	41.60	55.55	36.75
	Oil ($/bbl)	77.01	72.24	81.37	61.39
	Total ($/boe)	32.41	27.61	35.24	31.23

OPERATING NETBACKS ($/boe)
	Price	32.41	27.61	35.24	31.23
	Royalties	(4.96)	(1.21)	(6.15)	(3.83)
	Operating costs	(7.49)	(8.37)	(7.79)	(8.18)
	Transportation	(1.44)	(1.12)	(1.49)	(1.02)
	Total	18.52	16.91	19.81	18.20

CAPITAL ($000's)
	Drilling and completions	4,358	1,952	9,749	5,642
	Facilities	1,538	(152)	3,692	(179)
	Land and lease	211	3,661	1,933	5,551
	Seismic	868	196	1,427	343
	Capitalized general and administrative	814	781	2,084	2,342
	Total exploration & development	7,789	6,438	18,885	13,699
	Net property (dispositions) acquisition	(88)	194	(284)	(27,267)
	Other capital assets	-	3	21	10
	Total	7,701	6,635	18,622	(13,558)

(1) Cash flow is defined as cash flow from operations before changes in operating non-cash working capital;
(2) "Total net debt" is calculated by adding long-term debt less working capital (or plus working capital deficiency), excluding fair value of commodity contracts, current loss on sublease and associated future tax assets (liabilities).

Cash flow, cash flow per share (basic and diluted) and total net debt do not have standardized measures prescribed by Canadian generally accepted accounting principles and therefore may not be comparable with calculation measures for other issuers.

MANAGEMENT DISCUSSION & ANALYSIS

Management's Discussion and Analysis ("MD&A") is management's assessment of the financial and operating results of ProspEx Resources Ltd. ("ProspEx" or the "Company") as well as a prospective view of the Company's activities. The MD&A is for the three and nine months ended September 30, 2010, and was prepared as at November 12, 2010. The MD&A should be read in conjunction with the audited consolidated financial statements and MD&A for the year ended December 31, 2009 including the notes related thereto and the consolidated financial statements for the three and nine months ended September 30, 2010 together with the notes related thereto. The reader should be aware that historical results are not necessarily indicative of future performance.

RESULTS OF OPERATIONS

Operationally the third quarter was plagued by wet weather in the Company's main operating areas. Consequently, anticipated drilling was delayed to late in the quarter. ProspEx did participate in the drilling of three gross wells (1.5 net) during the quarter. Total capital expenditures in the quarter were $7.7 million.

Overall production levels were 36% higher than the third quarter of the prior year, but 13% lower than the previous quarter as no material new production was brought on stream during the quarter. Production gains compared to the prior year are a result of successful horizontal drilling in Kakwa.

Cash flow for the quarter rose to $3.3 million, 69% higher than the prior year's third quarter of $2.0 million, due to increases in production and commodity prices.

Subsequent to the third quarter of 2010 the Company completed a $5.5 million flow-through share issuance.

Business Environment

Overall business conditions remain fragile due to the slow recovery of the North American economy. Natural gas prices deteriorated in the third quarter, relative to the prior quarter, due to unfavourable supply and demand fundamentals in the North American natural gas markets.

ProspEx's current strategy is to direct spending towards evaluating and obtaining new opportunities. This strategy is focused on increasing the opportunity set available to the Company as business conditions improve, rather than short term production growth.

Revenue

($000's)	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30,2009
Natural gas	$ 4,856	$ 2,654	$ 17,846	$ 16,231
Realized gain on financial instruments	1,020	376	1,800	1,692
Total natural gas	5,876	3,030	19,646	17,923
Oil	142	247	553	849
Natural gas liquids	1,989	1,746	7,898	6,386
Oil and gas revenue	8,007	5,023	28,097	25,158
Unrealized (loss) gain on financial instruments	(653)	(401)	485	(919)
Total revenue	$ 7,354	$ 4,622	$ 28,582	$ 24,239

Third quarter oil and gas revenue increased by $3.0 million or 59% to $8.0 million in 2010, compared to $5.0 million in the third quarter of 2009. The increase in revenues for the quarter was due to the combination of higher production levels, stronger commodity prices and larger realized gains from the 2010 hedging program.

Production

	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
Area (boe/d)
Deep Basin	1,737	675	1,939	867
West Central Alberta	930	1,289	961	1,671
Southern Alberta	10	7	13	405
Other Areas	8	7	8	8
	2,685	1,978	2,921	2,951
Production
Natural gas (mcf/d)	13,477	8,906	14,250	13,585
Natural gas liquids (bbls/d)	419	456	521	637
Oil (bbls/d)	20	37	25	51
Total (boe/d)	2,685	1,978	2,921	2,951

Third quarter production increased 36% compared to the same quarter of the prior year, reflecting production gains from new horizontal wells drilled in Kakwa, offset by natural declines.

ProspEx's summer drilling program was delayed as wet weather conditions impaired surface access to drilling locations. This delay resulted in lower production levels in the third quarter compared to the previous quarter of the year.

Production in late 2010 is expected to be approximately 4,000 boe per day. Production at the start of 2010 was approximately 2,700 boe per day, therefore the forecasted 4,000 boe per day exit rate equates to approximately 50% production growth over the year.

With respect to the annual average production guidance of the Company for 2010, the Company is updating its prior guidance of approximately 3,100 to 3,300 boe per day. This guidance was made under the assumption that natural gas prices would be higher in 2010. In light of lower natural gas prices, the Company elected not to spend additional capital to maintain the pace of its capital spending program in the face of wet weather conditions. Accordingly, ProspEx now expects annual average production to be approximately 3,000 boe per day for 2010.

Commodity Pricing

ProspEx Average Prices		Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
Natural gas ($/mcf)
	Sales price	$ 3.92	$ 3.24	$ 4.59	$ 4.37
	Realized gain on financial instruments	0.82	0.46	0.46	0.46
		4.74	3.70	5.05	4.83
Oil ($/bbl)		77.01	72.24	81.37	61.39
NGL ($/bbl)		51.60	41.60	55.55	36.75
Average realized price ($/boe)		32.41	27.61	35.24	31.23
Unrealized (loss) gain on financial instruments ($/boe)		(2.64)	(2.21)	0.61	(1.14)
Total average price ($/boe)		$ 29.77	$ 25.40	$ 35.85	$ 30.09

Benchmark pricing	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
AECO C Spot ($/mcf)	$ 3.55	$ 2.94	$ 4.13	$ 3.77
Edmonton Par - light oil ($/bbl)	$ 74.46	$ 71.53	$ 76.57	$ 62.38

Average natural gas sales prices (prior to the effects of realized financial instruments) increased 21% to $3.92 per thousand cubic feet ("mcf") in the third quarter of 2010, compared to $3.24 per mcf in the third quarter of 2009. Third quarter 2010 average realized natural gas prices decreased 1% compared to the second quarter, as realized gains from financial instruments largely offset a 9% drop in AECO-C spot prices. Overall market sentiment still reflects concerns of a potential over-supply of the North American natural gas market.

Benchmark AECO C daily spot prices for natural gas increased 21% compared to the third quarter of 2009, which is in line with the increase in the Company's natural gas sales price.

Realized gains in the natural gas hedging program for 2010 increased the realized price for natural gas sales by $0.82 per mcf for the quarter and $0.46 per mcf on a year to date basis. The results of the hedging program reflect the Company's efforts to create a more predictable operating cash flow to ensure funding of the 2010 capital program.

Overall, oil and natural gas liquids ("NGLs") prices have improved, as the world economy slowly recovered over the past year. The price realized for NGL production in the third quarter of 2010 was $51.60 per barrel ("bbl"), an increase of 24% from $41.60 per bbl in the third quarter of 2009. Oil prices received for the third quarter of 2010 were $77.01 per bbl, an increase of 7% from the $72.24 per bbl received in the third quarter of 2009, consistent with the increase in benchmark pricing.

Financial Instruments

The impact of the changes in the fair values of open financial instruments during the quarter ended September 30, 2010 was an unrealized loss of $0.7 million and a year to date unrealized gain of $0.5 million. This compares to an unrealized loss of $0.4 million for the third quarter and an unrealized loss of $0.9 million year to date in 2009.

On a realized basis, gains from financial instruments were $1.0 million in the current quarter of 2010 and $1.8 million year to date.

The financial instruments open as of September 30, 2010 are described below:

*Type*	*Amount (GJ/day)*	*Term*	*Price ($/GJ at AECO)*	*Type*

Fixed	1,000	Oct. 1 - Oct. 31, 2010	$5.18	Financial
Fixed	1,000	Oct. 1 - Oct. 31, 2010	$5.385	Financial
Collar	1,000	Oct. 1 - Oct. 31, 2010	$5.00 - $6.16	Financial
Collar	1,000	Oct. 1 - Oct. 31, 2010	$5.00 - $5.90	Financial
Collar	1,000	Oct. 1 - Oct. 31, 2010	$4.90 - $5.63	Financial
Collar	1,000	Oct. 1 - Oct. 31, 2010	$5.00 - $5.95	Financial
Collar	1,000	Oct. 1 - Oct. 31, 2010	$4.75 - $5.86	Financial
Fixed	1,000	Oct. 1 - Oct. 31, 2010	$4.05	Financial
Fixed	1,000	Oct. 1 - Oct. 31, 2010	$3.96	Financial

These open financial instruments represent a mark to market asset at September 30, 2010 of $0.4 million, as current natural gas forward prices are below the minimum prices in the open financial instrument contracts.

Royalty Expenses

($000's)	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30,2009
Crown	$ 935	$ 20	$ 3,908	$ 1,994
Freehold and gross overriding	291	200	998	1,093
Total Royalties	$ 1,226	$ 220	$ 4,906	3,087

$ per boe	$ 4.96	$ 1.21	$ 6.15	$ 3.83
As a percentage of oil and gas revenue	15%	4%	17%	12%

In the third quarter of 2010, royalties totalled $1.2 million or 15% of revenue compared to the previous year's $0.2 million or 4% of revenue. The increase in total royalties paid in the third quarter compared to 2009 reflects the increases in production and stronger commodity prices in 2010.

During the first nine months of 2010 royalties totalled $4.9 million or 17% of oil & gas revenue compared to $3.1 million or 12% of oil & gas revenue for the same period of 2009. Crown royalty payments on a year to date basis have increased compared to the prior year, due to a shift in the Company's production mix towards higher productivity wells in the Kakwa area, adjustments in capital gas cost allowances, and the strengthening of commodity prices.

ProspEx is required to pay the Province of Alberta and other royalty owners for the right to produce minerals owned by them. Such royalty payments are subject to change and any changes may have an impact on the profitability of a project. On March 11, 2010, the Government of Alberta announced additional amendments to the new oil and gas royalty framework which are to come into effect on January 1, 2011. Under the most recent amendments, the maximum royalty rate for natural gas is to be reduced from 50% to 36% and the maximum royalty rate for conventional oil wells is to be reduced from 50% to 40%. In addition the New Well Incentive Program is to become a permanent feature to the new oil and gas royalty framework. Further refinements to the amendments were announced by the Government of Alberta on May 27, 2010 including finalization of the royalty curves that are to be utilized to determine the applicable royalty rates, and the indefinite extension and adjustments to the New Gas Deep Drilling Program.

Operating Costs

	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
Operating costs ($000's)	$ 1,850	$ 1,524	$ 6,214	$ 6,589
Operating costs ($/boe)	$ 7.49	$ 8.37	$ 7.79	$ 8.18

Operating costs for the third quarter were $1.9 million compared to $1.5 million in the third quarter of 2009. This increase is the result of higher production compared to the prior year.

Operating costs on a unit basis have decreased compared to 2009, reflecting the disposition of higher operating cost areas, and the addition of production from lower unit operating cost horizontal wells in Kakwa.

Transportation Expense

	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
Transportation expenses ($000's)	$ 355	$ 203	$ 1,192	$ 823
Transportation expenses ($/boe)	$ 1.44	$ 1.12	$ 1.49	$ 1.02

Transportation expense per boe for the three and nine months ended September 30, 2010 increased compared to the prior year, reflecting increases in production in operating areas that attract higher transportation rates and the disposition of production in areas with lower transportation rates.

General and Administrative Expenses

($000's)	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
Gross general and administrative	$ 1,937	$ 1,878	$ 5,180	$ 5,596
Recoveries	(217)	(197)	(765)	(598)
Capitalized expenses	(813)	(781)	(2,084)	(2,341)
Net general and administrative expenses	$ 907	$ 900	$ 2,331	$ 2,657
Net general and administrative expenses ($/boe)	$ 3.67	$ 4.95	$ 2.92	$ 3.30

General and administrative costs for the third quarter of 2010 remained approximately the same compared to the third quarter of 2009, although unit costs have declined due to increased production. For the first nine months of the year gross general and administrative costs are down from the same period of the prior year due to lower staffing levels in 2010.

Interest and Bank Charges

Interest and bank charges were $0.3 million in the third quarter and $0.8 million year to date in 2010, slightly lower than the prior year amount of $0.3 million in the third quarter and $1.0 million year to date. This is due to the Company operating at lower debt levels compared to the prior year.

Depletion, Depreciation and Accretion

	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
Depletion, depreciation and accretion ($000's)	$ 4,685	$ 5,457	$ 14,662	$ 22,446
Depletion, depreciation and accretion ($/boe)	$ 18.96	$ 29.99	$ 18.39	$ 27.86

Depletion, depreciation and accretion expense per boe in the third quarter of 2010 was $18.96 per boe. This is a 37% decrease from the third quarter 2009 rate of $29.99 per boe. This decrease is the result of reserve additions in the Kakwa operating area at the end of 2009 and the first quarter of 2010.

Income Taxes

In the third quarter of 2010, the Company had a future income tax reduction of $0.5 million compared to a reduction of $1.0 million in the same period of 2009. For the nine months ending September 30 the future income tax reduction in 2010 totaled $0.3 million, compared to a $4.0 million reduction in 2009.

Estimated tax pools as at September 30:

($000's)	2010	2009
Canadian development expense	$ 28,385	$ 38,856
Canadian exploration expense	38,206	33,067
Canadian oil & gas property expense	20,337	21,686
Undepreciated capital cost Non capital losses	26,166 14,847	32,852 -
Other	3,009	4,352
	$ 130,950	$ 130,813

Net Losses

The Company reported net losses of $1.6 million for the quarter and year to date periods ending September 30, 2010 compared to prior year losses of $3.1 million for the quarter and $9.2 million year to date. For the third quarter of 2010 the net loss was lower than the same period of the prior year due to higher production and commodity prices and a lower depletion, depreciation and accretion rate, partially offset by higher royalties. The net loss reported for the first nine months of the year was lower compared to 2009 due to a lower depletion, depreciation and accretion rate and higher commodity prices.

Capital Expenditures

($000's)	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
Drilling and completions	$ 4,358	$ 1,952	$ 9,749	$ 5,642
Facilities	1,538	(152)	3,692	(179)
Land and lease	211	3,661	1,933	5,551
Seismic	868	196	1,427	343
Capitalized G&A	814	781	2,084	2,342
Exploration & development capital expenditures	7,789	6,438	18,885	13,699
Net property (dispositions) acquisitions	(88)	194	(284)	(27,267)
Other capital expenditures	-	3	21	10
Total net capital expenditures	$ 7,701	$ 6,635	$ 18,622	$ (13,558)

The third well of the Kakwa program, located at 2-30-64-4W6 (the "2-30 well") has been drilled and is currently awaiting completion. Completion of this well is scheduled for late November, 2010.

Liquidity & Capital Resources

At September 30, 2010, ProspEx had the following financial resources available to fund its capital expenditure program.

($000's)
Working capital deficiency, excluding fair value of commodity contracts, current loss on sublease and associated future tax liabilities	$ (3,865)
Long-term debt	(24,258)
Bank facilities available	40,000
Total capital resources available	$ 11,877

ProspEx expects that it will be able to fund its 2010 capital program from operating cash flow and the capital resources noted above as well as the October 13, 2010 flow through share issuance as described below.

As at September 30, 2010, the Company's ratio of net debt to trailing quarterly operating cash flow was 1.9 to 1.0, which meets the Company's guidelines on capital management (which call for a maximum of 2.0 to 1.0). The Company continues to closely monitor its overall net debt levels and the resulting ratio to ensure proper debt levels are maintained.

Bank Debt

At September 30, 2010 the Company had a $40.0 million credit facility with a major Canadian bank. The facility revolves for 364 day periods, at which time the Company can request approval from the lender for an extension for an additional 364 day period or convert the outstanding bank indebtedness to a one year term loan. The amount of the facility is subject to a borrowing base test performed on a periodic basis by the lenders, based primarily on reserves and using commodity prices estimated by the lenders, as well as other factors. A decrease in the borrowing base could result in a reduction of the credit facility which may require a repayment to the lenders within sixty days of receiving notice of the new borrowing base. The credit facility provides that advances may be made by way of prime rate loans, guaranteed notes (bankers' acceptances) and letters of credit. The credit facility is tested quarterly, in arrears, and bears interest based on a sliding scale. The interest rate varies depending on the Company's debt to cash flow ratio determined quarterly on a grid system, with the grid ranging from debt to cash flow ranges of lower than 1.0:1.0 to greater than 3.0:1.0.

The facility is secured by a general security agreement conveying a first floating charge over all real and personal property and after acquired assets. The Company is required to meet certain covenants under the terms of this facility. As at September 30, 2010, the Company is in compliance with all covenants in accordance with the terms of the credit facility. The next scheduled review date of the facility is May 31, 2011.

Share Capital

As at September 30, 2010, ProspEx had 57,390,162 voting common shares ("Common Shares") (2009 - 57,385,162), no warrants (2009 - 2,016,269), and 2,511,500 options (2009 - 5,531,410) issued and outstanding. Each option, upon exercise, entitles the holder to one Common Share.

On October 13, 2010, the Company issued 3.1 million Common Shares on a flow-through basis at a price of $1.75 per share for total gross proceeds of $5.5 million. With this share offering ProspEx has committed to incur $5.5 million in qualifying expenditures by December 31, 2011.

As at November 12, 2010 ProspEx had 60,533,162 Common Shares, no warrants, and 2,511,500 options issued and outstanding.

Contractual Obligations

The Company has committed to certain payments as follows:

Payments due ($000's)	2010	2011	2012	2013	2014	Thereafter	Total
Long-term debt	$ -	$ 24,258	$ -	$ -	$ -	$ -	$ 24,258
Building lease	235	1,051	1,356	1,433	358	-	4,433
Processing fees	202	809	640	480	360	57	2,548
Transportation	284	984	741	602	210	-	2,821
Total	$ 721	$ 27,102	$ 2,737	$ 2,515	$ 928	$ 57	$ 34,060

The Company is committed to incur $5.5 million in qualifying expenditures related to the October 13, 2010 flow-through financing by December 31, 2011.

Off-Balance Sheet Arrangements

The Company has not entered into any off-balance sheet transactions other than previously discussed.

Summary of Quarterly Results

The following table summarizes the quarterly operating statistics of the Company.

			Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
			2010	2010	2010	2009	2009	2009	2009	2008

Average Daily Production
	Natural Gas (mcf/d)		13,477	14,996	14,288	11,327	8,906	14,382	17,561	16,868
	NGL (bbls/d)		419	562	583	557	456	645	811	719
	Oil (bbls/d)		20	26	29	32	37	47	69	57
	Total (boe/d)		2,685	3,086	2,994	2,477	1,978	3,089	3,807	3,587

Operating Netbacks ($/boe)
	Price ⁽¹⁾		$ 32.41	34.05	39.07	35.49	27.61	26.22	37.25	45.59
	Royalties		(4.96)	(7.49)	(5.85)	(5.15)	(1.21)	(1.21)	(7.37)	(8.18)
	Operating costs		(7.49)	(7.90)	(7.97)	(8.72)	(8.37)	(9.30)	(7.16)	(4.58)
	Transportation		(1.44)	(1.50)	(1.55)	(1.21)	(1.12)	(0.93)	(1.04)	(1.00)
	Total		$ 18.52	17.16	23.70	20.41	16.91	14.78	21.68	31.83

E&D Capital Spending ($000's)			$ 7,789	3,238	7,858	3,988	6,438	1,619	5,641	12,797

Selected Financial Results
($000's, except per share amounts)

	Oil and gas revenue		$ 8,007	9,564	10,526	8,088	5,023	7,370	12,765	15,046
	Unrealized financial instrument (loss) gain		(653)	(1,058)	2,196	(2)	(401)	310	(828)	(363)
	Net (loss) earnings		(1,626)	(1,900)	1,908	(1,231)	(3,082)	(3,899)	(2,225)	487
		Basic per share	$ (0.03)	(0.03)	0.03	(0.02)	(0.05)	(0.07)	(0.04)	0.01
		Diluted per share	$ (0.03)	(0.03)	0.03	(0.02)	(0.05)	(0.07)	(0.04)	0.01

⁽¹⁾ Price excludes unrealized financial instrument gain or loss.

Quarter to quarter results are influenced by many factors. The three main drivers are capital spending, production and commodity prices.

Capital spending is typically more heavily weighted to the winter drilling months, and therefore the fourth and first quarters of the year usually represent approximately 60% of the exploration and development budgets. The second quarter of each year usually has minimal capital spending, reflecting surface access restrictions due to spring break up conditions. Production additions typically lag capital spending by one or two quarters, resulting in production peaks in the second quarter of each year.

As previously mentioned, production is a key driver of overall quarterly results. Production is not only influenced by additions as a result of capital programs and subtractions as a result of dispositions, but also by natural declines as production from existing wells diminishes over time. With respect to the Company's overall quarterly production profile, production tends to peak in the second quarter of each year, reflecting new additions from the winter drilling programs, and the subsequent quarters reflect declining production as natural decline rates come into play. In 2009 this trend was further complicated by disposition activity and production curtailments due to low prices.

World-wide commodity price environments have a significant influence on the overall Company's quarterly results. The Company is a price-taker in the oil & gas industry and as a result, world prices drive Company revenues. Natural gas prices are currently low, driven by high natural gas storage inventories, strong domestic production levels in the United States, and reduced demand for natural gas as a result of the global economic downturn. In the face of this uncertainty, the Company has adopted a conservative approach by restricting exploration and development capital spending and as a consequence total net oil and gas revenues may not follow traditional quarterly cyclical trends in 2010.

INTERNATIONAL REPORTING STANDARDS
On January 1, 2011 International Financial Reporting Standards ("IFRS") will replace Canadian generally accepted accounting principles ("GAAP") for Canadian publicly accountable enterprises. Quarterly and annual results will be reported in accordance with IFRS beginning in 2011, with the restatement of 2010 amounts for comparative purposes. A project team was set up internally to lead the conversion project. The project team, as well as other key finance personnel, has attended industry specific IFRS educational programs. The Company has and will continue to involve the external auditors throughout the process and maintain regular progress reporting to the Audit Committee of the Board of Directors.

The Company's IFRS transition project includes four key phases:

project planning and scoping
draft policy and impact assessment
implementation and parallel reporting
ongoing monitoring and IFRS policy updates

Project Planning and Scoping
The Company has completed the project planning and scoping phase of the project. Project planning entailed developing a project plan, appointing internal staff and allocating resources. Scoping consisted of identifying and performing a high level impact analysis to identify areas that may be affected by the transition. The following areas are expected to change significantly for the Company:

property plant and equipment ("PP&E"), specifically treatment of exploration and evaluation costs, depreciation and depletion of property, plant and equipment and impairment of assets
asset retirement obligations
business combinations
future income taxes
more extensive presentation and disclosure

Future changes in IFRS prior to adoption may result in other accounting policy changes which could significantly impact the financial statements.

Draft Policy and Impact Assessment
The Company is currently in this phase of the project, which involves analyzing policy choices allowed under IFRS and assessing their impact on the financial statements. At this time, the Company's auditors are reviewing policy choices and preliminary impact calculations. The conclusion of this phase will require the Audit Committee of the Board of Directors to review and approve all accounting policy choices.

"IFRS 1" First Time Adoption of International Financial Reporting Standards provides a number of optional exemptions and mandatory exceptions to the general requirement for full retrospective application. This standard is only applicable to the opening balance sheet of the entity on transition to IFRS.

The following is a discussion of which IFRS 1 exemptions and exceptions the Company is considering using and the policy choices the Company has made or the progress of policy decisions for areas for which a significant change on conversion is anticipated:

Property, Plant and Equipment
ProspEx currently follows the full cost accounting guideline under Canadian GAAP resulting in the accumulation of all costs directly associated with the acquisition of, exploration for and development of oil and gas assets in one cost center. Costs are depleted using the unit of production method based on proved reserves. Under IFRS, costs previously accumulated in the full cost pool are capitalized as exploration and evaluation ("E&E") assets or developing and producing ("D&P") assets or expensed as E&E expenditures.

At transition to IFRS, new accounting policies must be adopted for E&E assets and expenditures and for D&P assets.

Costs incurred by the Company before acquiring the legal right to explore in an area, do not meet the definition of an asset under IFRS and therefore will likely be expensed by the Company as incurred. The Company does not expect these costs to be significant.
The Company intends to capitalize as E&E assets, costs for projects for which technical feasibility and commercial viability has not been determined but for which the legal right to explore in the area has been obtained. When the technical feasibility and commercial viability of the project is determined the costs will be transferred to D&P assets. The standard does not define technical feasibility and commercial viability. The Company intends to classify a project as technically feasible and commercially viable when proved plus provable reserves are assigned to the project. Unrecoverable costs associated with a project will likely be expensed. The Company does not intend to deplete any E&E assets.
D&P assets will likely be defined as expenditures on projects where technical feasibility and commercial viability have been determined. Under IFRS these costs should be capitalized and depleted on a unit of production basis using proved or proved plus probable reserves over a component level instead of by one company wide cost center. The Company intends to use proved plus probable reserves as a basis for depletion, and will likely have between eight and 12 components.

Under IFRS, impairment of assets is performed at the cash generating unit ("CGU") level which is a lower level than the country wide test currently required under Canadian GAAP. At this time the Company anticipates between two and four CGUs. Impairment tests may be performed using proved or proved plus probable reserves. The Company intends to test impairment using proved plus probable reserves.

On adoption of IFRS the Company has the option to retroactively restate PP&E or elect under IFRS 1 to measure PP&E at the date of transition at fair value or at the amount determined under Canadian GAAP. The Company will likely measure PP&E at the amount determined under Canadian GAAP. On transition, the PP&E balance will then be reclassified as E&E and D&P assets. The Company will first re-classify all E&E assets that are currently included in the PP&E balance on the balance sheet. The remaining PP&E balance will be the opening D&P asset value. The standard allows the Company to allocate the D&P asset balance to CGUs based on reserve volumes or values. The allocation method ProspEx intends to use is the net present value of proved plus probable company interest reserve cash flow values. Once oil and gas assets are allocated to cash generating units they are required to be tested for impairment, at the CGU level. Based on preliminary analysis PP&E will not be impaired on transition.

Decommissioning Liability
The decommissioning liability is currently referred to as asset retirement obligation under Canadian GAAP. IFRS 1 has an election which the Company plans to adopt, whereby the liability is measured at transition in accordance with IAS 37 Provisions, Contingent Liabilities and Contingent Assets, and any difference between that amount and the Canadian GAAP carrying amount of those liabilities at the date of transition is recognized in retained earnings. A major difference between current Canadian standards and IFRS appears to be the discount rate used to measure the asset retirement obligation. Under current Canadian standards a credit adjusted risk free rate is used in calculating the provision. Under IFRS, a risk free rate should be used when the expected cash flows are risked. Within the industry, there has been a debate on whether there should be a risk component applied to conventional property estimated cash outflows used in determining the provision. We are monitoring this matter and will be deciding which rate is the most appropriate in our circumstances. A lower discount rate will increase the provision on transition to IFRS with a corresponding charge to retained earnings or deficit.

Implementation and Parallel Reporting
This step will involve implementing all changes identified in the impact assessment phase including changes to information systems, business processes, and training of all staff impacted by the conversion. The Company's current data gathering and accounting system is capable of obtaining and recording data at a level of detail required for IFRS with slight modifications. Modifications include increasing the level of detail of which costs are tracked and adding new accounts.

Ongoing Monitoring and IFRS Policy Updates
The final phase of the project involves continuing education and training and ensuring maintenance of internal controls over IFRS financial reporting and disclosure control procedures.

The Company must also monitor all changes or anticipated changes in IFRS on an ongoing basis.

Business Activities
ProspEx has reviewed the impact of IFRS on its commodity price risk management practices, debt covenants and compensation arrangements and does not expect IFRS to have any significant changes in these areas.

Internal Control over Financial Reporting and Disclosure Controls and Procedures
Changes may be required to internal controls over financial reporting and disclosure controls and procedures with the implementation of IFRS. The implications will be analyzed once accounting policy choices and implementation plans are finalized.

DISCLOSURE CONTROLS AND POLICIES

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding required disclosure. The Company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of September 30, 2010, that the Company's disclosure controls and procedures as at such date are effective to provide reasonable assurance that material information related to the Company, including its consolidated subsidiary, is made known to them by others within those entities. It should be noted that while the Company's Chief Executive Officer and Chief Financial Officer believe that the Company's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

The Chief Executive Officer and Chief Financial Officer of the Company have caused under their supervision the design of internal controls over financial reporting ("ICFR"), and have evaluated the design and effectiveness of those controls. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer of the Company have concluded that the design and operating effectiveness of the Company's ICFR as of September 30, 2010 are effective and provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.

ICFR has inherent limitations no matter how well designed such controls may be. Control systems can only provide reasonable, not absolute, assurance that the objectives of the control systems are met.

There were no significant changes to the Company's ICFR during the third quarter of 2010.

ADVISORIES

Non-GAAP Measures
Within the MD&A references are made to terms commonly used in the oil and gas industry. The following terms are not defined by GAAP in Canada and are referred to as non-GAAP measures.

The following table provides reconciliation between cash flow from operations and cash flow for the periods below:

($000s)	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
Cash flow from operating activities	$ 2,846	$ 2,457	$ 11,037	$ 6,185
Change in non-cash working capital	485	(488)	1,033	3,980
Cash flow	$ 3,331	$ 1,969	$ 12,070	$ 10,165

The following table provides a reconciliation of total net debt for the periods below:

($000's)	As at September 30, 2010	As at September 30, 2009
Accounts receivable	$ (11,500)	$ (5,823)
Prepaid expenses	(332)	(319)
Accounts payable and accrued liabilities	15,697	8,836
Long-term debt	24,258	25,147
Total net debt	$ 28,123	$ 27,841

Barrel of oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of gas to one barrel of oil. The term "boe" may be misleading if used in isolation. A boe conversion ratio of one barrel of oil to six mcf of gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.

"Operating netbacks" are calculated by subtracting transportation costs, royalties and operating costs from the average price received during the period.

Forward-looking Information

Certain information regarding ProspEx including, without limitation, management's assessment of future plans and operations and anticipated production levels, constitutes forward-looking information or statements under applicable securities law and necessarily involve assumptions regarding factors and risks that could cause actual results to vary materially, including, without limitation, assumptions and risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, royalty rates, imprecision of reserve estimates, environmental risks, competition, incorrect assessment of the value of acquisitions or dispositions, failure to realize the anticipated benefits of acquisitions and ability to access sufficient capital from internal and external sources.

The reader is cautioned that these factors and risks are difficult to predict and that the assumptions used in the preparation of such information, although considered reasonable by ProspEx at the time of preparation, may prove to be incorrect. Accordingly, readers are cautioned that the actual results achieved will vary from the information provided herein and the variations may be material. Readers are also cautioned that the foregoing list of assumptions, factors and risks is not exhaustive. Additional information on the foregoing assumptions, risks and other factors that could affect ProspEx's operations or financial results are included in ProspEx's public disclosure documents on file with Canadian securities regulatory authorities. In particular see "Description of the Business - Risk Factors and Industry Conditions" in ProspEx's most recent Annual Information Form. ProspEx's reports may be accessed through the SEDAR website (www.sedar.com), at ProspEx's website (www.psx.ca) or by contacting the Company directly. Consequently, there is no representation by ProspEx that actual results achieved will be the same in whole or in part as those set out in the forward-looking information.

Furthermore, the forward-looking information and statements contained in this MD&A are made as of the date of this MD&A, and ProspEx does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. The forward-looking information and statements contained herein are expressly qualified by this cautionary statement.

ProspEx Resources Ltd.
Consolidated Balance Sheets
(unaudited)


(Stated in thousands of dollars)			September 30, 2010	December 31, 2009

Assets

Current assets
	Accounts receivable	$	11,500	$ 7,800
	Prepaid expenses		332	389
	Future income tax asset (note 2)		-	27
	Fair value of commodity contracts (note 4)		392	-
			12,224	8,216

Property, plant and equipment, net			150,728	145,939

Total assets		$	162,952	$ 154,155

Liabilities

Current liabilities
	Accounts payable and accrued liabilities	$	15,697	$ 12,599
	Current loss on sublease		204	226
	Fair value of commodity contracts (note 4)		-	93
	Future income tax liability (note 2)		53	-
			15,954	12,918

Long-term debt (note 1)			24,258	17,234
Asset retirement obligation			3,730	3,810
Other long-term liabilities			68	198
Future income tax liability (note 2)			4,879	5,160

Total liabilities			48,889	39,320

Shareholders' Equity

Common shares (note 3 a)			90,800	90,800
Contributed surplus (note 3 b)			9,833	8,987
Retained earnings			13,430	15,048
Total shareholders' equity			114,063	114,835

		$	162,952	$ 154,155

Commitments (note 6)
Subsequent event (note 7)
See accompanying notes to consolidated financial statements

ProspEx Resources Ltd.
Consolidated Statements of Loss, Comprehensive Loss and Retained Earnings
For the periods ended
(unaudited)

	(Stated in thousands of dollars, except per share amounts)		Three months ended September 30, 2010		Three months ended September 30, 2009		Nine months ended September 30, 2010		Nine months ended September 30, 2009

Revenue
	Oil and gas	$	8,007	$	5,023	$	28,097	$	25,158
	Unrealized financial instrument (loss) gain (note 4)		(653)		(401)		485		(919)
	Royalties		(1,226)		(220)		(4,906)		(3,087)

			6,128		4,402		23,676		21,152

Expenses
	Depletion, depreciation and accretion		4,685		5,457		14,662		22,446
	Operating		1,850		1,524		6,214		6,589
	Transportation		355		203		1,192		823
	General and administrative		907		900		2,331		2,657
	Interest and bank charges		262		276		809		1,030
	Stock-based compensation		188		124		425		332
	Sublease loss		-		-		-		524

			8,247		8,484		25,633		34,401

Loss before income taxes			(2,119)		(4,082)		(1,957)		(13,249)

Income taxes (note 2)
	Future reduction		(493)		(1,000)		(339)		(4,043)

Net loss and comprehensive loss for the period			(1,626)		(3,082)		(1,618)		(9,206)

Retained earnings, beginning of period			15,056		19,361		15,048		25,485

Retained earnings, end of period		$	13,430	$	16,279	$	13,430	$	16,279

Net loss per share
	Basic	$	(0.03)	$	(0.05)	$	(0.03)	$	(0.16)
	Diluted	$	(0.03)	$	(0.05)	$	(0.03)	$	(0.16)

See accompanying notes to consolidated financial statements

ProspEx Resources Ltd.
Consolidated Statements of Cash Flows
For the periods ended
(unaudited)

(Stated in thousands of dollars)			Three months ended September 30, 2010		Three months ended September 30, 2009		Nine months ended September 30, 2010		Nine months ended September 30, 2009

Operations
Net loss for the period		$	(1,626)	$	(3,082)	$	(1,618)	$	(9,206)
	Items not involving cash
	Depletion, depreciation and accretion		4,685		5,457		14,662		22,446
	Stock-based compensation		188		124		425		332
	Sublease loss		-		-		-		524
	Rent inducement		-		161		-		161
	Future income tax reduction		(493)		(1,000)		(339)		(4,043)
	Unrealized financial instrument loss (gain)		653		401		(485)		919
Amortization of rent inducements			(27)		(21)		(82)		(21)
Amortization of sublease loss			(58)		(62)		(169)		(62)
Asset retirement expenditures			9		(9)		(324)		(885)
			3,331		1,969		12,070		10,165
Changes in non-cash working capital			(485)		488		(1,033)		(3,980)
			2,846		2,457		11,037		6,185

Financing
	Increase (decrease) in long-term debt		2,566		4,197		7,024		(15,660)
	Issuance of common shares		(8)		(2)		(8)		(2)
			2,558		4,195		7,016		(15,662)

Investments
	Exploration and development expenditures		(7,789)		(6,438)		(18,885)		(13,699)
	Proceeds on property disposal		88		-		284		28,964
	Property acquisition		-		(194)		-		(1,697)
	Other capital expenditures		-		(3)		(21)		(10)
			(7,701)		(6,635)		(18,622)		13,558
Changes in non-cash working capital			2,297		(17)		569		(4,081)
			(5,404)		(6,652)		(18,053)		9,477
Change in cash			-		-		-		-
Cash, beginning of period			-		-		-		-
Cash, end of period		$	-	$	-	$	-	$	-

Additional cash flow disclosure (note 5)

See accompanying notes to consolidated financial statements

Notes to Consolidated Financial Statements
For the three and nine months ended September 30, 2010 and 2009
(unaudited)

The interim unaudited consolidated financial statements of ProspEx Resources Ltd. (the "Company" and/or "ProspEx") have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). The Company is engaged in the acquisition, exploration, development and production of oil and natural gas in Canada.

The interim unaudited consolidated financial statements have been prepared by management following the same accounting policies and methods of computation as the audited consolidated financial statements for the period ended December 31, 2009. Preparation of financial statements in conformity with Canadian GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses and disclosure of contingent assets and liabilities at the date of the financial statements. Actual results may differ from these estimates. In the opinion of management, these interim consolidated financial statements contain all adjustments of a normal and recurring nature to present fairly the Company's financial position as at September 30, 2010 and the results of its operations and cash flows for the three and nine months ended September 30, 2010. The disclosures included below are incremental to those included with the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto for the year ended December 31, 2009.

1. LONG TERM DEBT

2. FUTURE INCOME TAXES

The provision for future income taxes differs from the amount computed by applying the combined expected Canadian Federal and Provincial tax rates to earnings before income taxes. The reasons for these differences are as follows:

($000's)			Three months ended September 30, 2010		Three months ended September 30, 2009		Nine months ended September 30, 2010		Nine months ended September 30, 2009
Loss before income taxes		$	(2,119)	$	(4,082)	$	(1,957)	$	(13,249)
Combined statutory rate (%)			28%		29%		28%		29%
Computed expected future income tax reduction			(593)		(1,184)		(548)		(3,842)
Increase (decrease) in taxes resulting from:
	Stock-based compensation expensed		53		36		119		96
	Effect of change in tax rate		47		135		83		(355)
	Other		-		13		7		58
Income tax reduction		$	(493)	$	(1,000)	$	(339)	$	(4,043)

The components of the future income tax liability are as follows:

($000's)			September 30, 2010		December 31, 2009
	Property, plant and equipment	$	(5,418)	$	(5,900)
	Fair value of commodity contracts		(110)		27
	Asset retirement obligation		932		952
	Loss due to leasing arrangements		102		146
	Share issue costs		62		142
			(4,432)		(4,633)
Valuation allowance			(500)		(500)
Future income tax liability		$	(4,932)	$	(5,133)

At September 30, 2010, the Company had estimated tax pools available to reduce future taxable income of $131.0 million (December 31, 2009 - $124.5 million).

On October 13, 2010, the Company issued 3.1 million voting common shares ("Common Shares") on a flow-through basis at a price of $1.75 per share for total gross proceeds of $5.5 million. With this share offering ProspEx has committed to incur $5.5 million in qualifying expenditures by December 31, 2011.

Capitalized stock based compensation resulted in an increase to future tax liabilities of $0.1 million during the nine months ended September 30, 2010 (2009 - $0.1 million).

3. SHAREHOLDERS' EQUITY

(a) Common Shares & Common Share Performance Warrants Issued

		Nine months ended September 30, 2010		Nine months ended September 30, 2009
		Number of Shares/Warrants	Amount	Number of Shares/Warrants	Amount
		(000's)	($000's)	(000's)	($000's)
Common Shares
	Balance at the beginning of the period	57,385	$ 90,800	57,385	$ 90,802
	Issued on exercise of stock options	5	6	-	-
	Issue costs, net of future tax reduction	-	(10)	-	(2)
	Adjustment to contributed surplus for options exercised	-	4	-	-
	Balance at end of the period	57,390	90,800	57,385	$ 90,800
Common Share performance warrants
	Balance at the beginning and end of the period	-	$ -	2,016	$ 1,233

(b) Contributed Surplus

($000's)	Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
Balance at the beginning of the period	$ 9,460	$ 7,175	$ 8,987	$ 6,758
Stock-based compensation	377	248	850	665
Exercise of stock options	(4)	-	(4)	-
Balance at the end of the period	$ 9,833	$ 7,423	$ 9,833	$ 7,423

(c) Stock Options

Changes in outstanding stock options are summarized below:

	Nine months ended September 30, 2010			Nine months ended September 30, 2009
	Options (000's)		Weighted Average Exercise Price	Options (000's)		Weighted Average Exercise Price
Outstanding at beginning of period	5,261	$	2.34	5,160	$	3.44
Granted	-		-	1,112		0.66
Exercised	(5)		1.25	-		-
Forfeited	(191)		2.49	(741)		3.51
Expired	(85)		3.22	-		-
Cancelled	(2,468)		3.78	-		-
Outstanding at end of period	2,512	$	0.88	5,531	$	2.88

The following table summarizes stock options outstanding and exercisable at September 30, 2010:

	Options outstanding			Options exercisable
Range of exercise price	Number outstanding at period end (000's)	Weighted average remaining contractual life (years)	Weighted average exercise price	Number exercisable at period end (000's)	Weighted average exercise price
$ 0.61 - $ 0.70	1,082	3.7	$ 0.66	361	$ 0.66
$ 0.96 - $ 1.25	1,403	3.9	$ 1.01	82	$ 1.25
$ 3.28	27	2.4	$ 3.28	18	$ 3.28
	2,512	3.8	$ 0.88	461	$ 0.87

The estimated fair values of the options are being amortized against earnings and capitalized to property, plant and equipment over the vesting period. During the three months ended September 30, 2010, a total of $0.2 million (2009 - $0.1 million) of stock-based compensation was recorded against income and $0.2 million (2009 - $0.1 million) was capitalized. During the nine months ended September 30, 2010, a total of $0.4 million (2009 - $0.3 million) of stock-based compensation was recorded against income and $0.4 million (2009 - $0.3 million) was capitalized.

(d) Per Share Amounts

		Three months ended September 30, 2010	Three months ended September 30, 2009	Nine months ended September 30, 2010	Nine months ended September 30, 2009
Weighted average Common Shares basic		57,387,988	57,385,162	57,386,114	57,385,162
Dilutive securities:
	Stock options	-	-	-	-
Diluted		57,387,988	57,385,162	57,386,114	57,385,162

For both the three and nine months ended September 30, 2010, all options and warrants outstanding (2009 - all options and warrants outstanding) were excluded from the diluted calculations as they were anti-dilutive to the earnings (loss) per share calculations.

4. FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT STRATEGY

Overview

The Company has exposure to a number of risks from its use of financial instruments including:

• Credit risk

• Liquidity risk

• Market risk

This note presents information about the Company's exposure to each of the above risks and the Company's objectives, policies and processes for measuring and managing risk, and the Company's management of capital. Further quantitative disclosures are included throughout these financial statements.

The Board of Directors has overall responsibility for the establishment and oversight of the Company's risk management framework. The Board has implemented and monitors compliance with risk management policies.

The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities.

Fair Value of Financial Instruments
The fair value of measurements recognized in the balance sheet are classified according to the following hierarchy based on the amount of observable inputs used to value the instrument.

Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1. Prices are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the market place.
Level 3 - Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

	September 30, 2010
	Fair Value	Level 1	Level 2	Level 3
Commodity Contracts	392	-	392	-

The Company's use of financial instruments has been assessed on the fair value hierarchy described above and the natural gas contracts are classified as Level 2.

The carrying value of the Company's financial instruments, other than long-term debt approximates their fair value due to their short maturity. The fair value of the long-term debt was determined using quoted borrowing rates and therefore was considered Level 2. At September 30, 2010, the fair value of the long-term debt approximated its carrying value.

Credit Risk
Credit risk relates to the Company's receivables from joint interest partners and petroleum and natural gas marketers and the risk of financial loss if a customer, partner or counterparty to a financial instrument fails to meet its contractual obligations. A substantial portion of the Company's accounts receivable are with customers in the energy industry and are subject to normal industry credit risk. The Company generally grants unsecured credit but routinely assesses the financial strength of its partners and marketers.

Receivables from petroleum and natural gas marketers are normally collected on the 25^thday of the month following production. The Company sells the majority of its production to three petroleum and natural gas marketers therefore is subject to concentration risk. To date the Company has not experienced any collection issues with its petroleum and natural gas marketers. Joint interest receivables are typically collected within one to three months of the joint interest bill being issued to the partner. The Company attempts to mitigate the risk from joint interest receivables by obtaining joint interest partners approval of significant capital expenditures prior to expenditure. The Company does not typically obtain collateral from petroleum and natural gas marketers or joint interest partners; however in certain circumstances, it may elect to cash call a joint interest partner in advance of the work.

As at September 30, 2010 the Company's receivables consisted of $6.7 million (December 31, 2009 - $2.7 million) from joint interest partners, $2.5 million (December 31, 2009 - $3.5 million) of receivables from petroleum and natural gas marketers and $2.3 million (December 31, 2009 - $1.6 million) of other receivables. Of the $11.5 million in total accounts receivable, $0.2 million is aged over 90 days.

The carrying amount of accounts receivable and cash and cash equivalents represents the maximum credit exposure. The Company does not have an allowance for doubtful accounts as at September 30, 2010 and did not provide for any doubtful accounts nor was it required to write-off any receivables during the quarter ended September 30, 2010.

Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. The Company's approach to managing liquidity is to attempt to ensure, as far as practicable, that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company's reputation.

The Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures. To facilitate the capital expenditure program, the Company has a revolving reserve based credit facility, as outlined in note 1. The Company also attempts to match its payment cycle with collection of petroleum and natural gas revenues on the 25^th day of each month.

The following are the contractual maturities of financial liabilities and associated interest payments due as at September 30, 2010:


Financial Liability ($000's)	< 1 year	1 - 2 years	2 - 5 years	Thereafter
Accounts payable and accrued liabilities	$ 15,697	-	-	-
Long-term debt	-	24,258	-	-
Total	$ 15,697	24,258	-	-

Market risk
Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company's net earnings or the value of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns.

The Company utilizes both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.

Foreign Currency Exchange Risk
Foreign currency exchange rate risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company's petroleum and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for petroleum and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollars. Given that changes in exchange rate have an indirect influence, the impact of changing exchange rates cannot be accurately quantified. The Company had no forward exchange rate contracts in place as at or during the three and nine months ended September 30, 2010 and 2009.

Commodity Price Risk
Commodity price risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by world economic events that dictate the levels of supply and demand. The Company attempts to mitigate commodity price risk through the use of financial derivative sales contracts. The following contracts were in place as of September 30, 2010:

Type

Amount (GJ/day)

Term

Price ($/GJ at AECO)

Type

Fixed

1,000

Oct. 1 - Oct. 31, 2010

$5.18

Financial

Fixed

1,000

Oct. 1 - Oct. 31, 2010

$5.385

Financial

Collar

1,000

Oct. 1 - Oct. 31, 2010

$5.00 - $6.16

Financial

Collar

1,000

Oct. 1 - Oct. 31, 2010

$5.00 - $5.90

Financial

Collar

1,000

Oct. 1 - Oct. 31, 2010

$4.90 - $5.63

Financial

Collar

1,000

Oct. 1 - Oct. 31, 2010

$5.00 - $5.95

Financial

Collar

1,000

Oct. 1 - Oct. 31, 2010

$4.75 - $5.86

Financial

Fixed

1,000

Oct. 1 - Oct. 31, 2010

$4.05

Financial

Fixed

1,000

Oct. 1 - Oct. 31, 2010

$3.96

Financial

The contracts in place during the three months ended September 30, 2010 resulted in an unrealized loss of $0.7 million (September 30, 2009 - $0.4 million unrealized loss) and a realized gain of $1.0 million (September 30, 2009 - $0.4 million realized gain). During the nine months ended September 30, 2010 the contracts in place resulted an unrealized gain of $0.5 million (2009 - $0.9 million unrealized loss) and a realized gain of $1.8 million (2009 - $1.7 million realized gain).

With respect to commodity prices, during the three months ended September 30, 2010, a one dollar increase in the price per GJ of natural gas relevant only to the Company's production dedicated to derivative financial instruments would have resulted in a net earnings decrease of $0.1 million (2009 - $0.1 million). A one dollar decrease in the price per GJ of natural gas on the same production would have increased net earnings after taxes for the three months ended September 30, 2010 by $0.1 million (2009 - net earnings increase of $0.1 million). This excludes any impact relating to unrealized financial instrument gains/losses.

Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate fluctuations on its credit facility which bears a floating rate of interest. The Company had no interest rate swaps or financial contracts in place as at or during the three and nine months ended September 30, 2010. For the three and nine months ended September 30, 2010, a difference in the interest rate of 1% would change net earnings after tax by an estimated $0.1 million (2009 - $0.1 million and $0.2 million), assuming all other variables are constant.

Capital Management Strategy

The Company's policy on capital management is to maintain a prudent capital structure to allow the Company to fund future development. The Company considers its capital structure to include shareholders' equity, bank debt, and working capital.

($000's)	September 30, 2010	December 31, 2009
Shareholders' equity	$ 114,063	$ 114,835
Long-term debt	24,258	17,234
Working capital deficiency excluding fair value of commodity contracts, current loss on sublease and associated future taxes	3,865	4,410

The Company manages its capital programs in order to maintain a prudent capital structure as changes in economic conditions occur. The Company may and has from time to time issued shares and adjusted spending to manage current or projected operating cash flows and debt levels.

The Company monitors its capital base using the ratio of net debt to trailing quarterly operating cash flow. This ratio is calculated as net debt, as defined as long-term debt less working capital (or plus working capital deficiency) excluding unrealized financial instrument gain (loss), current loss on sublease and associated future taxes; divided by cash flow from operations before changes in non-cash working capital (of the last four operating quarters). The Company's guideline is to maintain a ratio of approximately 1.0 to 1.0, not exceeding 2.0 to 1.0. This ratio will fluctuate depending on fluctuations of the commodity and business cycles. The Company prepares annual capital expenditure budgets which are updated periodically to monitor this ratio. The annual budget is approved by the Board of Directors with updates reviewed by the Board throughout the year.

As at September 30, 2010 the Company's ratio of net debt to trailing quarterly operating cash flow was 1.9 to1.0, and compares to the annual ratio of 1.7 to 1.0 for the year ended December 31, 2009.

The Company's share capital is not subject to any external restrictions. The bank debt facility has no restrictions other than the limitation of borrowing under the facility on an annual basis and an adjusted working capital covenant ratio of 1.0 to 1.0. As at September 30, 2010, the Company is in compliance with all bank facility requirements.

There have been no changes to the Company's capital management strategy during the quarter ended September 30, 2010.

5. ADDITIONAL DISCLOSURES

Interest and Taxes Paid

Net cash interest paid during the quarter was $0.3 million (2009 - $0.2 million). Cash taxes paid during the period was $nil (2009 - $nil). On a year to date basis, net cash interest paid to September 30, 2010 was $0.7 million (2009 - $0.7 million). Year to date cash taxes paid to September 30, 2010 was $nil (2009 - $nil).

6. COMMITMENTS

The Company has committed to certain future payments as follows:

Payments due ($000's)	2010	2011	2012	2013	2014	Thereafter	Total
Long-term debt	$ -	$ 24,258	$ -	$ -	$ -	$ -	$ 24,258
Building lease	235	1,051	1,356	1,433	358	-	4,433
Processing fees	202	809	640	480	360	57	2,548
Transportation	284	984	741	602	210	-	2,821
Total	$ 721	$ 27,102	$ 2,737	$ 2,515	$ 928	$ 57	$ 34,060

The Company is committed to incur $5.5 million in qualifying expenditures related to the October 13, 2010 flow-through financing by December 31, 2011.

7. SUBSEQUENT EVENT

%SEDAR: 00021285E

For further information:

John Rossall, President & CEO or George Yee, Vice President Finance & Chief Financial Officer, at [email protected], or (403) 268-3940

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