Pengrowth Energy F10 Registration of securities | PGH 28 Aug 06

Exhibit 4.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

This MD&A has been prepared as of August 2, 2006.

The following discussion and analysis (“MD&A”) of financial and operating results should be read in conjunction with the unaudited interim consolidated financial statements for the three and six months ended June 30, 2006 (contained in this quarterly report) and the audited consolidated financial statements and MD&A of Esprit Energy Trust for the year ended December 31, 2005. All amounts are in Canadian dollars unless otherwise noted. All references to “Esprit” or the “Trust” refer to Esprit Energy Trust and all references to the “Company” refer to Esprit Exploration Ltd. The Trust is an open-ended investment trust created pursuant to a trust indenture. The Company is a subsidiary of the Trust.

Per barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of 6,000 cubic feet of natural gas to one barrel (“bbl”) of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 1 bbl:6,000 cubic feet is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. References to “production volumes” or “production” refer to average sales volumes.

References are made to terms commonly used in the oil and gas industry that are not defined by generally accepted accounting principles (“GAAP”) in Canada and are referred to as non-GAAP measures. Such non-GAAP measures should not be considered an alternative to, or more meaningful than GAAP measures as indicators of the Trust’s financial or operating performance. The non-GAAP measures presented are not standardized measures and therefore may not be comparable with the calculation of similar measures for other entities. The following are descriptions of non-GAAP measures used in this MD&A:


	1. “Cash flow” equals cash flow from operations before changes in non-cash working capital. The Trust considers cash flow to be a key measure as it demonstrates the Trust’s ability to generate the cash necessary to pay distributions, repay debt and to fund future capital investment. Cash flow per unit is calculated using the same number of units for the period as used in the net earnings per unit calculations.

	2. “Net debt” equals bank loans and convertible debentures plus current liabilities minus current assets. Net debt is a useful measure of the Trust’s total leverage.

	3. “Net debt to cash flow ratio” equals the net debt (as defined above) divided by cash flow (as defined above). Net debt to cash flow ratio is a useful measure by which to compare the Trust’s financial leverage to those of its peers.

	4. “Operating netback” equals total revenue per boe less royalties per boe and operating costs per boe. Operating netbacks are a useful measure to compare the Trust’s operations with those of its peers.

	5. “Payout ratio” equals total distributions as a percentage of cash flow for the period. Payout ratio is a useful measure used by management to analyze the Trust’s efficiency and sustainability.

	6. “Finding and development costs” equals exploration and development capital plus the change in future development costs divided by reserve additions (including reserve revisions). Finding and development costs are used by management as a measure of the cost effectiveness of the Trust.

	7. “Finding, development and acquisition costs” equals all capital (including acquisitions) divided by reserve additions (including acquisitions and reserve revisions). Finding, development and acquisition costs are used by management as a measure of the cost effectiveness of the Trust.

This MD&A contains forward-looking or outlook information with respect to the Trust. Certain information regarding Esprit Energy Trust, including management’s assessment of future plans and operations, 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, imprecision of reserve estimates, environmental risks, competition, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions and ability to access sufficient capital

from internal and external sources. Forward-looking statements include, but are not limited to: Esprit’s guidance, production performance, finding and operating costs, drilling program completion and results and other statements containing the words “expects”, “believes”, “will”, “should” or similar such language. 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 reasonably accurate by Esprit 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 factors is not exhaustive. Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A, and Esprit 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. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

IMPORTANT ADDITIONAL INFORMATION WILL BE FILED WITH THE SEC

In connection with the proposed merger of Esprit and Pengrowth, Pengrowth intends to file relevant materials with the Securities and Exchange Commission (the “SEC”) on a Registration Statement on Form F-10 (the “Registration Statement”) to register the Pengrowth units to be issued in connection with the proposed transaction.Investors and unit holders are urged to read the Registration Statement and any other relevant documents to be filed with the SEC when available because they will contain important information about Pengrowth and Esprit, the transaction and related matters. Investors and unit holders will be able to obtain free copies of the Registration Statement and other documents filed with the SEC by Pengrowth through the web site maintained by the SEC at www.sec.gov. In addition, investors and unitholders will be able to obtain free copies of the Registration Statement and such other documents when they become available from Pengrowth by contacting Pengrowth Investor Relations at investorrelations@pengrowth.com or by telephone at 403-233-0224 or toll free at 1-888-744-1111.

VISION, CORE BUSINESS AND STRATEGY

Esprit is an oil and gas income trust with high quality assets located in Alberta and Saskatchewan. Our solid base of natural gas weighted reserves is complemented by experienced and talented teams of professionals who are focused on creating value for our unitholders.

Esprit is based on a sustainable business model. We apply capital efficient plans to develop our existing assets and to maximize their value. Our operations have been organized around four key operating areas, each with a team dedicated to executing its operating and capital plans and accountable for its results.

We continually work to grow and enhance our existing asset base with value-adding strategic acquisitions. Opportunities are screened, analyzed and must meet both strategic and financial benchmarks before being pursued.

At Esprit, we are committed to a high level of integrity.We have great respect for the environment we operate in, the people in whose communities we operate, our employees and other service providers and all the stakeholders who invest in our Trust. We strive to continually provide transparent, open and timely information about our business.


	*SUBSEQUENT EVENTS*

On June 15, 2006, Esprit announced the acquisition of Trifecta Resources Inc. (“Trifecta”), a private oil and gas producer. The effective date of this acquisition was July 5, 2006 and the total consideration paid was approximately $102 million, funded from the Trust’s existing credit lines. The acquisition is expected to add approximately 1,500 boe per day to production through the second half of 2006 and 4.9 million boe of proved plus probable reserves. The assets included in the acquisition complement Esprit’s existing asset base with the majority of the assets located within the Trust’s key operating area of greater Olds. The assets also include low-risk growth opportunities that add to the Trust’s development inventory.

On July 24, 2006, Esprit announced that it had entered into an agreement to combine with Pengrowth Energy Trust (“Pengrowth”), creating a well-balanced, diversified trust with high quality assets and excellent development opportunities. Under the agreement, each Esprit unit will be exchanged for 0.53 of a Pengrowth unit. In addition, Esprit’s Board of Trustees intends to pay a $0.30 per unit special distribution. This special distribution is expected to be paid immediately prior to the closing of the transaction. Including the special distribution, the total consideration to be received by Esprit Unitholders represents a 26 percent premium on the closing prices on July 21, 2006 for each of the Esprit and Pengrowth units. The transaction is subject to unitholder approval and regulatory approval and is expected to close on or about September 28, 2006.

NET EARNINGS AND CASH FLOW


	Three Months Ended										Six Months Ended

	Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
	2006		2005		2006		2005		2005		2006		2005

	($ thousands except per unit amounts)
Net earnings		18,412		15,906		19,592		25,052		22,465		38,004		26,935
Net earnings per unit — basic		0.28		0.28		0.30		0.38		0.35		0.57		0.55
Net earnings per unit — diluted		0.27		0.27		0.29		0.37		0.34		0.55		0.53
Cash flow		38,843		30,504		45,933		56,149		45,143		84,774		52,961
Cash flow per unit — basic		0.58		0.54		0.69		0.86		0.70		1.28		1.09
Cash flow per unit — diluted		0.53		0.52		0.63		0.78		0.64		1.16		1.04
Basic weighted average units		66,462		56,802		66,388		65,521		64,533		66,424		48,576
Diluted weighted average units		75,566		58,961		74,824		74,117		71,914		75,542		50,743
Cash distributions per unit		0.45		0.42		0.45		0.45		0.42		0.90		0.84

Cash flow for the second quarter of 2006 was $38.8 million, 27 percent higher than the cash flow we generated in the same quarter last year. The increased cash flow was largely a result of increased production levels. Higher oil and natural gas liquids prices also contributed to the increase, but were partially offset by lower natural gas prices in the quarter. Increased costs for royalties, operating, general and administrative and interest costs further offset the impact of production increases.

Compared to the previous quarter, cash flow was down by 15 percent, due in most part to lower natural gas prices.

Year-to-date cash flow was $84.8 million, up 60 percent over the first six months of 2005. Higher commodity prices and higher production levels were the main drivers, partially offset again by higher royalties, operating, general and administrative and interest costs.

Net earnings for the second quarter of 2006 were $18.4 million, a 16 percent increase compared to the second quarter of 2005 and a six percent decrease from the previous period. In addition to the items that affected our cash flow, earnings were impacted by increased depletion, depreciation and amortization and unit-based compensation costs. A recovery of future income taxes resulting from a change in the effective tax rate partially offset the increased costs.

Year-to-date net earnings were $38.0 million, up 41 percent over the first six months of 2005. In addition to the items that affected our cash flow,year-to-date earnings were also impacted by increased depletion, depreciation and amortization and unit-based compensation costs partially offset by lower future income taxes.

More information on the items affecting cash flow and earnings is provided in the detailed discussion below.

OIL AND NATURAL GAS REVENUE


		Three Months Ended										Six Months Ended

		Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
		2006		2005		2006		2005		2005		2006		2005

Oil and gas revenue ($ thousands)			77,658		57,940		88,274		105,526		83,761		165,931		100,997
Production volumes
	Natural gas (mcf/d)		74,266		65,709		77,116		79,494		79,056		75,683		60,366
	Natural gas liquids (bbl/d)		1,858		1,357		1,768		1,725		1,424		1,813		1,334
	Oil (bbl/d)		3,004		1,216		2,818		2,840		2,159		2,912		807

	Total (boe/d)		17,240		13,525		17,439		17,814		16,759		17,339		12,202
Sales prices(1)
	Natural gas ($/mcf)		7.29		7.56		9.48		10.97		8.60		8.40		7.40
	Natural gas liquids ($/bbl)		67.39		58.43		65.17		70.84		63.94		66.31		56.80
	Crude oil ($/bbl)		62.20		50.07		47.84		53.76		64.60		55.29		44.33


(1)	Sales prices are after hedging gains (losses)

Oil and natural gas revenue for the second quarter was $77.7 million, an increase of $19.7 million or 34 percent from the same quarter last year. This increase was driven by a combination of higher production volumes and increased commodity prices. Higher production levels contributed $16.7 million of the increased revenue in the second quarter. The remaining $3.0 million of increased revenue was due to higher commodity prices in the quarter. Natural gas prices actually dropped in the quarter compared to the same quarter last year, causing a reduction in revenue of approximately $1.8 million. However this was more than offset by higher oil and natural gas liquids prices.

Compared to the previous quarter, oil and gas revenue was down 12 percent. This variance is mostly due to lower natural gas prices in the quarter, partially offset by stronger oil prices. During the quarter, commodity prices remained volatile. Oil prices rose strongly in the quarter reflecting increased geo-political tension. On the other hand, natural gas prices trended lower in the quarter, impacted by high storage levels caused mainly by a warmer than usual winter.

Year-to-date oil and gas revenue was $165.9 million, up $64.9 million or 64 percent on the first six months of 2005. Higher volumes contributed $42.1 million to this increase while higher commodity prices contributed $22.9 million.


	*PRODUCTION*


	Three Months Ended															Six Months Ended

	Jun 30			Jun 30			Mar 31			Dec 31			Sep 30			Jun 30			Jun 30
	2006			2005			2006			2005			2005			2006			2005

Natural gas (mcf/d)		74,266			65,709			77,116			79,494			79,056			75,683			60,366
Natural gas liquids (bbl/d)		1,858			1,357			1,768			1,725			1,424			1,813			1,334
Oil (bbl/d)		3,004			1,216			2,818			2,840			2,159			2,912			807

Total (boe/d)		17,240			13,525			17,439			17,814			16,759			17,339			12,202

Natural gas		72	%		81	%		74	%		74	%		79	%		73	%		82	%
Natural gas liquids		11	%		10	%		10	%		10	%		8	%		10	%		11	%
Oil		17	%		9	%		16	%		16	%		13	%		17	%		7	%

Total		100	%		100	%		100	%		100	%		100	%		100	%		100	%

We reported stable production volumes in the second quarter of 2006, with volumes averaging 17,240 boe per day for the quarter. This was an increase of 27 percent from the same quarter last year and was basically unchanged from the previous quarter. Successful drilling at Greater Olds, Saskatchewan and Southern Alberta combined with a strong optimization focus at Greater Olds and Central Alberta offset natural declines.Year-to-date production was 17,339 boe per day, up 42 percent from the first six months of 2005. The higher production level compared to the previous year is due to several acquisitions completed in 2005 and the Trust’s successful drilling.

Esprit’s production mix continues to follow a trend of increased oil weighting. For the second quarter of 2006, our production was 72 percent natural gas, down from 74 percent in the previous quarter and 81 percent in the second quarter of 2005.Year-to-date production was 73 percent natural gas weighted compared to 82 percent for the same period last year. The increased oil production is mainly attributable to successful drilling and acquisitions in our Saskatchewan and Southern Alberta operating areas. Our production mix is expected to be further impacted by the production associated with the Trifecta acquisition. This incremental production is split 50 percent natural gas, 25 percent natural gas liquids and 25 percent light oil.


	*PRODUCTION BY KEY OPERATING AREA*


	Three Months Ended										Six Months Ended

	Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
	2006		2005		2006		2005		2005		2006		2005

	(boe per day)
Greater Olds		8,106		6,377		7,983		7,688		7,392		8,045		6,995
Southern Alberta		3,346		2,110		3,373		3,393		3,253		3,360		1,061
Saskatchewan		1,206		371		952		760		601		1,080		341
Central Alberta		4,527		4,460		5,112		5,492		5,452		4,817		3,671
Minor Areas		55		207		19		481		61		37		134

Total		17,240		13,525		17,439		17,814		16,759		17,339		12,202

Our second quarter andyear-to-date production of 17,240 and 17,339 boe per day respectively, were in line with our expectations. We anticipate that the addition of the Trifecta assets in the third quarter will further strengthen Esprit’s asset base and we expect it to add production of approximately 1,500 boe per day for the last half of 2006.


	*PRICES AND PRODUCT MARKETING*


	AVERAGE SELLING PRICE⁽¹⁾


											Six Months
	Three Months Ended										Ended

	Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
	2006		2005		2006		2005		2005		2006		2005

Natural gas ($/mcf)		7.29		7.56		9.48		10.97		8.60		8.40		7.40
Natural gas liquids ($/bbl)		67.39		58.43		65.17		70.84		63.94		66.31		56.80
Crude oil ($/bbl)		62.20		50.07		47.84		53.76		64.60		55.29		44.33

Total ($/boe)		49.50		47.08		56.24		64.39		54.33		52.87		45.73


⁽¹⁾	Price is after hedging gains (losses)


	AVERAGE BENCHMARK PRICING


											Six Months
	Three Months Ended										Ended

	Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
	2006		2005		2006		2005		2005		2006		2005

Alberta Reference Price⁽¹⁾(C$/GJ)		5.83		6.55		7.79		10.91		7.93		6.81		6.32
AECO (30 day) natural gas (C$/GJ)		5.95		6.99		8.79		11.08		7.75		7.37		6.67
NYMEX natural gas (US$/mmbtu)		6.82		6.80		9.08		12.85		8.25		7.95		6.56
WTI crude oil (US$/bbl)		70.70		53.17		63.48		60.02		63.19		67.09		51.51
US$/CDN$ exchange rate		1.12		1.24		1.15		1.17		1.20		1.14		1.24


⁽¹⁾	Alberta Reference Price for second quarter 2006 is the expected price as June actual prices are not available at time of release

During the second quarter, natural gas prices continued to decline from the high levels experienced at the end of 2005. High natural gas storage levels, caused by a warmer than usual winter, put downward pressure on natural gas prices. Benchmark prices for natural gas dropped in the United States by 25 percent and 32 percent in Canada.

We received an average price for our natural gas in the quarter of $7.29 per mcf ($6.68 per gigajoule (“GJ”)) after hedging, a decrease of four percent over the same quarter last year and a 23 percent decrease from the previous quarter. Our price in the quarter was $0.85 per GJ above the expected Alberta Reference Price in the second quarter of $5.83 per GJ. The Alberta Reference Price is the average plant gate price received by all Alberta gas producers for their product and is published by the Department of Energy of the Province of Alberta.

Year to date, our natural gas price averaged $8.40 per mcf ($7.69 per GJ) compared to an estimated Alberta Reference Price of $6.81 per GJ for the same period and to an average of $7.40 per mcf for the first six months of 2005.

During the second quarter of the year, we sold our natural gas liquids for an average price of $67.39 per barrel. This was an increase of 15 percent from the same quarter last year and an increase of three percent from the previous quarter. Year to date, our natural gas liquids price has averaged $66.31 per barrel, an increase of 17 percent from the same period last year. Prices for natural gas liquids have been impacted by the movement of oil prices over these periods.

Our average oil price in the second quarter of 2006 was $62.20 per bbl, an increase of 24 percent from the same period last year and an increase of 30 percent from the previous quarter. Year to date our oil price has averaged $55.29 per barrel, a 25 percent increase from the same period last year. Increased geo-political tension and limited refining capacity were reflected in the higher oil prices experienced during the quarter. Heavy oil differentials narrowed, also having a positive impact on the price we received for our oil.

Energy commodity prices can fluctuate due to changes in the geo-political environment, weather conditions, supply disruptions and variations in demand. We use commodity price hedges to limit the volatility in our cash flow and, in turn, provide stability to our distributions. We have a written policy delegating certain authorities to management to manage commodity price risk. The Board of Trustees regularly meets with Esprit’s management to review our hedging strategy and the hedges in place. In the case of a material acquisition, we may use hedges on a larger portion of the acquired production to protect the transaction economics.

For the first half of the year, our hedging activities increased our oil and gas revenue by $6.9 million or $2.20 per boe. This was made up of a gain of $7.5 million ($0.55 per mcf) for natural gas and a loss of $0.6 million ($1.14 per barrel) for oil.

For the second half of the year, we have approximately 18 percent of our estimated annual natural gas production and 22 percent of our estimated oil production hedged using fixed price contracts. We also have eight percent of our natural gas volumes protected by costless collars which provide downside price protection

but also remove the benefit of prices above a specified level. The estimated production level for 2006 includes forecast production from the Trifecta assets acquired in the third quarter of 2006. A portion of the hedges were put in place following the Trifecta acquisition in order to protect the economics of the transaction.

If all of Esprit’s commodity price risk management contracts were closed out on June 30, 2006, the gain resulting from the settlement would have been approximately $5.9 million, made up of a gain of $12.9 million on the natural gas contracts and a loss of $7.0 million on the oil contracts. At August 2, 2006 the loss that would have resulted from closing all of our contracts was $10.9 million, made up of a loss of $0.8 million from natural gas and a loss of $10.1 million from oil.


	NETBACK SUMMARY

In the second quarter, our operating netback was $29.16 per boe, an increase of three percent compared to the same quarter last year, and a decrease of 12 percent compared to the previous quarter. Year to date, our operating netback was $31.18 per boe, up 15 percent from the first six months of 2005. Netbacks were higher than the previous year comparatives largely due to higher commodity prices, partly offset by higher royalty and operating and general and administrative costs. Netbacks decreased from the previous quarter due to lower sales prices, higher operating and general and administrative costs partly offset by lower royalties.


	Three Months Ended															Six Months Ended

	Jun 30			Jun 30			Mar 31			Dec 31			Sep 30			Jun 30			Jun 30
	2006			2005			2006			2005			2005			2006			2005

	($/boe)
Price⁽¹⁾		49.50			47.08			56.24			64.39			54.33			52.87			45.73
Royalties		(10.89	)		(9.90	)		(13.76	)		(16.93	)		(11.37	)		(12.33	)		(10.13	)
Operating costs		(9.07	)		(8.46	)		(8.86	)		(9.05	)		(9.40	)		(8.96	)		(8.07	)
Transportation costs		(0.38	)		(0.45	)		(0.43	)		(0.45	)		(0.47	)		(0.40	)		(0.44	)

Operating netback		29.16			28.27			33.19			37.96			33.09			31.18			27.09
General and Administrative costs		(2.46	)		(1.59	)		(1.93	)		(1.47	)		(1.37	)		(2.20	)		(1.60	)

Netback		26.70			26.68			31.26			36.49			31.72			28.98			25.49


⁽¹⁾	Price is after hedging gains (losses)

ROYALTIES


	Three Months Ended										Six Months Ended

	Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
	2006		2005		2006		2005		2005		2006		2005

Total royalties (net of ARTC) ($ thousands)		17,090		12,182		21,594		27,739		17,534		38,684		22,372
As a % of oil and gas sales		22		21		25		26		21		23		22
Per boe		10.89		9.90		13.76		16.93		11.37		12.33		10.13

For the second quarter of 2006, our royalty costs were $17.1 million ($10.89 per boe) compared to $12.2 million ($9.90 per boe) for the same period last year and $21.6 million ($13.76 per boe) in the previous quarter.Year-to-date royalty costs were $38.7 million ($12.33 per boe) compared to $22.4 million ($10.13 per boe) in the first six months of 2005, reflecting both increased production levels and increased commodity prices. Royalty costs are directly impacted by changes in commodity prices. Our per unit royalty costs declined in the second quarter compared to the last two quarters due to several non-recurring adjustments.

OPERATING COSTS


	Three Months Ended										Six Months Ended

	Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
	2006		2005		2006		2005		2005		2006		2005

Operating expenses ($ thousands)		14,227		10,412		13,907		14,838		14,488		28,134		17,824
Per boe		9.07		8.46		8.86		9.05		9.40		8.96		8.07

Operating costs for the second quarter of the year were $14.2 million ($9.07 per boe) up from $10.4 million ($8.46 per boe) in the same period last year and $13.9 million ($8.86 per boe) in the previous quarter.Year-to-date operating costs were $28.1 million ($8.96 per boe) compared to $17.8 million ($8.07 per boe) for the first six months of 2005.

Over the past year, costs in the oil and gas sector have increased significantly. Higher energy prices have increased the range of economic opportunities and resulted in much higher levels of overall industry activity. This in turn, has created significant increases in the industry’s cost base. The increase in our operating costs over the past year reflects this higher cost structure. Recently, costs have begun to stabilize however we do not expect them to be materially lower going forward.

TRANSPORTATION COSTS


											Six Months
	Three Months Ended										Ended

	Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
	2006		2005		2006		2005		2005		2006		2005

Transportation costs ($ thousands)		592		558		674		743		730		1,265		977
Per boe		0.38		0.45		0.43		0.45		0.47		0.40		0.44

For the second quarter of 2006, our transportation costs were $0.6 million ($0.38 per boe) compared to $0.6 million ($0.45 per boe) for the same period last year and $0.7 million ($0.43 per boe) in the previous quarter.Year-to-date transportation costs were $1.3 million ($0.40 per boe) compared to $1.0 million ($0.44 per boe) in the first six months of 2005. The lower transportation costs in 2006 were achieved through transportation streamlining efforts. The Trust incurs transportation costs which are defined as the costs incurred to move a saleable quality product to the point of sale.

DEPLETION, DEPRECIATION & AMORTIZATION


	Three Months Ended										Six Months Ended

	Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
	2006		2005		2006		2005		2005		2006		2005

Depletion, depreciation and amortization ($ thousands)		25,559		15,821		25,173		26,270		22,506		50,732		26,008
Per boe		16.29		12.85		16.04		16.03		14.60		16.17		11.77

For the first quarter of 2006, our depletion, depreciation and amortization (DD&A) costs were $25.6 million ($16.29 per boe) compared to $15.8 million ($12.85 per boe) in the same quarter last year and $25.2 million ($16.04 per boe) in the previous quarter.Year-to-date DD&A costs were $50.7 million ($16.17 per boe) compared to $26.0 million ($11.77 per boe) for the first six months of 2005. The calculation of these costs is impacted by a number of factors; the most significant being the cost of adding reserves to our asset base. The DD&A rate of $16.17 per boe is reflective of Esprit’s historic costs of acquiring, finding and developing oil and gas reserves which have been impacted by increasing industry costs.

GENERAL AND ADMINISTRATIVE


											Six Months
	Three Months Ended										Ended

	Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
	2006		2005		2006		2005		2005		2006		2005

General and administrative costs ($ thousands)		3,862		1,957		3,037		2,414		2,109		6,899		3,529
Per boe		2.46		1.59		1.93		1.47		1.37		2.20		1.60

General and administrative costs for the first quarter were $3.9 million ($2.46 per boe) compared to $2.0 million ($1.59 per boe) in the same period last year and $3.0 million ($1.93 per boe) in the previous quarter.Year-to-date general and administrative costs were $6.9 million ($2.20 per boe) compared to $3.5 million ($1.60 per boe) for the first six months of 2005. A large part of this increase is due to rising industry compensation and retention costs and an increased staff level. The employment market in Alberta remains very tight and Esprit needs to remain competitive in order to retain and attract quality staff.

INTEREST AND FINANCING CHARGES


											Six Months
	Three Months Ended										Ended

	Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
	2006		2005		2006		2005		2005		2006		2005

	($ thousands)
Interest on bank loans		1,842		1,124		1,865		1,618		1,294		3,706		2,008
Interest on Debentures		1,579		—		1,536		1,589		1,138		3,115		—
Amortization of Debenture issue costs		164		—		189		347		174		352		—
Accretion of debt portion of Debentures⁽¹⁾		92		—		98		100		71		191		—

Total interest and financing charges		3,677		1,124		3,688		3,655		2,677		7,364		2,008


⁽¹⁾	In accordance with generally accepted accounting principles, the fair value to the conversion feature of the Debentures is classified as equity and the remainder is classified as debt. Over the term of the Debentures, the debt portion will accrete up to the principal balance at maturity with the charge going to interest and financing expenses.

In the second quarter of the year, our interest expense was $3.7 million, up $2.6 million from the same quarter last year and relatively unchanged from the previous quarter.Year-to-date interest expenses were $7.4 million, up 267 percent from the same period last year. In the third quarter of 2005, we issued $100 million of 6.5 percent convertible unsecured subordinated debentures. A large portion of the increase in total interest and financing charges was due to the interest, accretion and amortization of financing charges related to these debentures. The increase in interest on bank loans was a result of higher average bank debt compared to the same period in 2005 and a higher average interest rate. The increase in our average bank debt is mostly due to the debt we assumed with the acquisition of Resolute Energy Inc. in the second quarter of 2005. The average annual interest rate on the utilized portion of the credit facility was 4.8 percent in the first half of 2006 compared to 3.5 percent in the same period last year.

UNIT-BASED COMPENSATION

During the quarter, we recorded unit-based compensation costs of $2.7 million compared to $0.8 million for the same quarter last year. Year to date, unit based compensation costs have totaled $3.1 million compared to $1.2 million for the first six months of 2005. The increased costs in the second quarter of 2006 reflect changes in the calculation parameters due to the proposed merger with Pengrowth.

INCOME TAXES

We did not pay any current income taxes in the first half of 2006, with the exception of Saskatchewan capital tax of $0.3 million. During the second quarter, the federal government announced the abolishment of Large Corporations Tax effective January 1, 2006. In the second quarter, Esprit reversed the amounts it had previously accrued for Large Corporations Tax of approximately $0.3 million.

Future income taxes arise from differences between the accounting and tax basis of the operating company’s assets and liabilities. In the Trust structure, interest and net profits interest payments are made between the operating company and the Trust and ultimately paid to the unitholders in the form of distributions. This mechanism transfers the majority of the income and tax liability to the unitholders. It is therefore expected that Esprit will not incur any cash income taxes in the medium term under current commodity prices.

CAPITAL EXPENDITURES


	Three Months Ended											Six Months Ended

	Jun 30		Jun 30		Mar 31			Dec 31		Sep 30		Jun 30			Jun 30
	2006		2005		2006			2005		2005		2006			2005

	($ thousands)
Exploration and development expenditures		15,424		18,334		15,428			25,261		25,334		30,852			28,788
Acquisitions & dispositions		—		6,971		(16,000	)		181		99,745		(16,000	)		7,000
Office & computer assets		703		246		162			145		150		865			328

Total		16,127		25,551		(410	)		25,587		125,229		15,717			36,116

During the second quarter of the year, we spent approximately $16.1 million in capital expenditures. We had a fairly active quarter with 14 gross (10 net) wells drilled and several optimization projects. Year to date, we have spent $31.7 million in capital and have received $16.0 million from the disposition of non-core assets. Our drilling program had an 86 percent success rate in the quarter; 87 percent year to date.

In the quarter, we spent $15.4 million of exploration and development capital which was focused mainly in our Olds, Berry and southeast Saskatchewan areas. We also spent approximately $0.7 million on office and computer assets which was largely for leasehold improvements.

At Olds, we tied in the successful Viking well drilled in the previous quarter and drilled a second Viking well. We are currently evaluating the results on this well. We also participated in two farm-out wells and one non-operated Pekisko well in the quarter which were all successful. During the quarter, we completed several optimization projects and continued to make progress on the approvals for our deeper Crossfield program planned for later in the year.

In Southern Alberta, we continued development drilling at our Richdale Banff oil pool. We drilled one well during the quarter and started another in late June. The first well was not successful in the Banff zone but was successfully completed in a shallower gas-producing zone. The Banff zone in the second well has now been perforated and results to date appear encouraging. During the quarter, we ran a10-well re-completion pilot at our Winnifred property, unfortunately this program was not successful. We have identified a further 30 re-completion opportunities at our Berry property. In addition, we drilled four wells targeting the Mannville section in the quarter. Three of these wells were successful and have now been cased and are awaiting tie-in.

In Saskatchewan, we drilled two successful horizontal wells into the Alida formation at our southeast Saskatchewan property. Initial production rates from these wells totaled 650 barrels of oil per day and exceeded our expectations.

Optimization activity continued in our Central Alberta area. During the quarter, we also drilled an unsuccessful well at Beaverlodge and participated in a non-operated Blue-sky re-completion and two successful non-operated wells.

LIQUIDITY AND CAPITAL RESOURCES


		Three Months Ended										Six Months Ended

		Jun 30		Jun 30		Mar 31		Dec 31		Sep 30		Jun 30		Jun 30
As at		2006		2005		2006		2005		2005		2006		2005

		($ thousands, except ratios)
Bank loans			141,830		133,814		135,231		144,239		148,691		141,830		133,814
Working capital deficiency			13,900		18,299		13,318		20,785		16,470		13,900		18,299

Net debt			155,730		152,113		148,549		165,024		165,161		155,730		152,113
	(excluding debentures)
Convertible debentures			94,057		—		93,964		93,866		97,254		94,057		—

Total net debt			249,787		152,113		242,513		258,890		262,415		249,787		152,113
Bank loans to cash flow ratio			0.9		1.1		0.7		0.6		0.8		0.8		1.3
Net debt (excluding debentures) to cash flow ratio			1.0		1.2		0.8		0.7		0.9		0.9		1.4
Total net debt to cash flow ratio			1.6		1.2		1.3		1.2		1.5		1.5		1.4
Outstanding units			66,494		64,523		66,416		66,358		64,573		66,494		64,523

On July 28, 2005, we issued $100 million of 6.5 percent convertible unsecured subordinated debentures and received $96.0 million, net of issuance costs. These Debentures pay interest semi-annually. They are convertible at the option of the holder at any time and convert into fully paid trust units at $13.85 per trust unit. The Debentures mature on December 31, 2010. The net proceeds were used to fund the acquisitions of Markedon Energy Ltd. and Monroe Energy Inc.

The Debentures have been classified as debt, net of the fair value of the conversion feature which has been classified as part of unitholders’ equity. The issue costs have been recorded as a deferred asset and will be amortized over the term of the Debentures. The debt portion will accrete up to the principal balance at maturity. The accretion, amortization of issue costs and the interest payable are expensed within interest and financing charges on the consolidated statements of earnings.

Esprit’s liquidity and capital requirements are met through operating cash flow and existing credit facilities. During the first six months of the year, cash flow exceeded distributions and capital expenditures by approximately $9.3 million.

At June 30, 2006, our net debt, excluding debentures, was $155.7 million and was made up of $141.8 million outstanding on our senior credit facility and a working capital deficiency of $13.9 million. This reflects a 1.0 times net debt (excluding debentures) to cash flow ratio based on second quarter annualized cash flow. Total net debt was $249.8 million and, in addition to the bank loan and working capital deficiency, includes $94.1 million of Debentures. This represents a 1.6 times total net debt to cash flow ratio, based on annualized second quarter 2006 cash flow.

In conjunction with the acquisition of Trifecta Resources Inc., we expanded our existing senior credit facility by $50 million to $330 million. This credit facility was used to fund the acquisition with total consideration of approximately $102 million.

Future debt levels are primarily dependent on our cash flow, distributions and capital program. The credit facility, together with cash flow, is expected to be sufficient to meet Esprit’s near term capital requirements and provide the flexibility to pursue profitable growth opportunities. A significant decline in oil and natural gas prices and/ or a significant reduction in our oil and gas reserves could impact our access to bank credit facilities and our ability to fund operations and maintain distributions.

We do not have any off balance sheet financing arrangements.

OUTSTANDING TRUST UNIT DATA

Esprit’s trust units trade on the Toronto Stock Exchange under the symbol EEE.UN.At August 2, 2006, we had 66,498,553 Trust units and 387,759 exchangeable shares outstanding. A total of 492,473 units are issuable upon conversion of the exchangeable shares using the exchange ratio at July 17, 2006. During the first six months of 2006, a total of 74,675 exchangeable shares have been exchanged for trust units.

During the first six months of 2006, the trust units traded in the range of $10.87 to $13.79 with an average daily trading volume of approximately 317,000 units.

Esprit has a Performance Unit Incentive Plan that was created at the time we reorganized into a trust. Under the Performance Unit Incentive Plan, the trustees may grant up to five percent of the number of Trust units outstanding from time to time to trustees, officers, employees of, or providers of services to the Trust. Currently there are 3.3 million performance units issuable under the Performance Unit Incentive Plan. The majority of these performance units vest over a period of three years. The number of Trust units ultimately issued under the Performance Unit Incentive Plan is dependant on our performance relative to our peers and other performance criteria. The Trust granted 403,834 performance units (net of cancelled and exercised performance units) during the first six months of 2006. We have recorded compensation expense of $3.1 million ($1.7 million was capitalized) and contributed surplus of $4.1 million in the first half of 2006 based on the estimated fair value of the outstanding performance units on the date of grant and our best estimate of the performance factor applied in calculating the number of Trust Units issuable under the plan.

CASH DISTRIBUTIONS

In the first six months of the year, we continued to pay distributions of $0.15 per unit per month. We paid out a total of 70 percent of the cash flow generated in the period.

Our capital program is financed from the residual cash flow and additional draw-downs on the bank facility if required. The key drivers of our cash flow, as is generally the case with other energy trusts, are commodity prices and production. Since Esprit’s production is heavily weighted to natural gas (72 percent in the quarter), natural gas prices have a significant effect on our cash flow. In the event that oil and natural gas prices are higher than anticipated and a cash surplus develops in a quarter, the surplus may be used to increase distributions, reduce debt, and/or increase the capital program. In the event that oil and natural gas prices and/or production are lower than expected, we may decrease distributions, increase debt or decrease the capital program. We regularly review our distribution policy in the context of the current commodity price environment and production levels.

At Esprit, we pay distributions monthly to unitholders of record on the last business day of the month. Distributions are paid on the 15th of the following month or the following business day where the 15th falls on a weekend. The Board of Trustees determines the amount of the distribution after considering factors such as the commodity price environment, production levels and the amount of capital expenditures to be funded from cash flow.

We expect that approximately 20 percent of theyear-to-date 2006 distributions will represent a tax efficient return of capital to Canadian unitholders and will reduce the adjusted cost base of the trust units held by unitholders. For unitholders resident in the United States, taxability of distributions is calculated using U.S. tax rules. The taxable portion of the monthly distribution is calculated annually based on current and accumulated earnings in accordance with U.S. tax law. In 2005, 65.28 percent of the 2005 distributions were dividends that were “Qualifying Dividends”. The remaining 34.72 percent was a tax-deferred reduction to the cost of the units for tax purposes.

OUTLOOK

The second quarter was another strong quarter for Esprit. A combination of successful drilling and a focus on optimizing our base production allowed us to maintain stable production. During the quarter we announced the acquisition of Trifecta which we believe further strengthens our asset base. The majority of the acquired

assets are complementary to our existing asset base and are expected to benefit from our operational expertise and control of infrastructure in the area.

We believe that the proposed combination with Pengrowth is a very positive step for the future of Esprit and for its unitholders. The broader asset base, deeper inventory of development opportunities and strong management team should provide a solid future for unitholders.

QUARTERLY OPERATING RESULTS


			2006				2005								2004

			Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3⁽¹⁾

			(In $ thousands of dollars, except per unit amounts)
Oil and gas revenue				77,658		88,274		105,526		83,761		57,940		43,057		44,856		46,851
Net earnings				18,412		19,592		25,052		22,465		15,906		11,029		12,179		(185	)
Net earnings per unit — basic				0.28		0.30		0.38		0.35		0.28		0.27		0.31		(0.01	)
		— diluted		0.27		0.29		0.37		0.34		0.27		0.27		0.29		(0.01	)
Cash flow				38,843		45,933		56,149		45,143		30,504		22,458		23,791		13,880
Cash flow per unit — basic				0.58		0.69		0.86		0.70		0.54		0.56		0.60		0.34
	— diluted			0.53		0.63		0.78		0.64		0.52		0.53		0.56		0.34


⁽¹⁾	A loss was recorded in the period as a result of $8.3 million of transaction costs incurred relating to the transformation to a Trust.

OTHER INFORMATION ON THE TRUST

Other information concerning the Trust, including the Annual Information Form, can be located at www.sedar.com under the profile Esprit Energy Trust or at Esprit’s web site at www.eee.ca

READER’S ADVISORY:


	•	Certain comparative amounts have been reclassified to conform to current period presentation.

	•	In accordance with NI 51-101 all numbers stated in barrel of oil equivalent have been converted on the basis of 6 mcf equals 1 boe, unless otherwise stated.

Pengrowth Energy (PGH) Inactive F-10Registration of securities (Canada)