Accrete Energy Inc.
TSX : GZ

Accrete Energy Inc.

March 22, 2007 22:39 ET

Accrete Energy Inc. Announces Year-End Results

CALGARY, ALBERTA--(CCNMatthews - March 22, 2007) - Accrete Energy Inc. (TSX:GZ) is pleased to announce the operational and financial results for the year ended December 31, 2006.

Accrete Energy Inc. is an independent oil and gas exploitation and production company with a focussed base of production, balanced drilling portfolio and an extensive development program in Company operated properties situated in Alberta, Canada. All financial results are expressed in Canadian dollars.
The year 2006 proved to be another exciting period in the oil and gas industry. Strong commodity pricing early in the year fuelled exploration, development and M&A activities to record levels This strong pricing environment helped to provide some of the $51 million the Company spent on capital projects resulting in exceptional production and reserve growth.

The Company's mandate for the Harmattan area was to design a capital program which would increase production and working interest throughput at our facilities. The Company has realized production increases of more than 100% from the previous year as a result of these efforts.

The Claresholm area continues to produce in a predictable and low cost manner. Although no additional reserves or production additions came about in 2006, two exploratory wells were drilled in the first quarter of 2007 which renewed further exploratory interest in this area.

Near term growth will come from the Pouce Coupe area in Northwestern Alberta. The Company has drilled two wells and participated in two others and has further plans to drill another 3 wells in this area throughout the year. Production from these wells is expected in early 2007.

In the longer term the Company will benefit from exploratory efforts in the Edson (Ansell) and Saxon areas of west central Alberta. The Edson area provides a multi-objective, resource style project within a logistically challenging area. Two wells were drilled and completed in this project in 2006 followed by two more wells in the first quarter of 2007.The results from this cursory round of drilling will provide the Company with a foundation from which it can build its geological and geophysical models.

The Saxon area is in it's infancy from an exploration perspective. One well was drilled in early 2007 to test our geologic concepts however the future of this project rests on the Company's ability to acquire additional lands and seismic.

The decision by our current federal government to enact changes to the tax structure of Income Trusts has caused a great deal of uncertainty and confusion in the minds of both the Industry and the Market. Despite this potential setback, the Company intends to continue to focus on low cost, high quality asset growth through the drill bit.

OPERATIONAL UPDATE

With the release of the Company's year end results which follow, Accrete is giving a brief operational update in order to highlight the Company's continued activity and success.

The Company has been active in all five of its core areas with the drilling of six wells and the completion of 11 wells. Tie-in of all of these wells is progressing in various stages dependant to a large extent on weather and regulatory approvals.

At Harmattan additional zones in existing producing wells have been completed. Production has increased by an estimated 140 boe's (net). Two new Cardium oil wells drilled late last year are currently being tied in and one well on a new trend is drilling.

The Company has acquired additional interest in 256 hectares (92 hectares net) of land along its producing trend which has been assigned proven reserves of 160,000 boe's net to the Company.

At Granum the Company has cased and completed 2 gas wells in which it holds an 80% working interest. These wells will be tied in to the Company's existing facility at Claresholm within the next few weeks. The Company has identified 4 additional locations based on 3D seismic.

At Edson the Company drilled 2 multi-zone gas wells in which it holds 100% working interest. Completion and testing of these wells is still on going. Tie-in of these wells is likely to occur in the 3rd and 4th quarter's dependant on accessibility.

At Saxon the Company has drilled 1 multi zone gas well and is undergoing testing with tie-in alternatives being considered. Plans are also underway to shoot additional 3D seismic.

At Pouce Coupe the Company has brought on 1 of 3 gas wells drilled late last year with the other 2 wells anticipated to be tied-in in the next few weeks. Production from the first well is being constrained by the existing pipeline pressure at approximately 80 boe's(80 boe's net). A number of infill locations have been identified.

HIGHLIGHTS

- Annual average production was 2,540 barrels of oil equivalent per day ("boe/d") a 99 % increase over 2005 production of 1,276 boe/d

- Cash flow was $19.7 million for the year ended December 31, 2006 as opposed to $13.5 million for the equivalent period last year

- Cash flow for the year ended December 31, 2006 was $1.28 per share basic , a 44 % increase over 2005 cash flow of $0.89 per share basic

- Net earnings was $4.0 million for the year ended December 31, 2006 versus $3.3 million for the same period in 2005

- Issued 1,248,300 flow-through shares at a price of $8.40 per share resulting in net proceeds of $10,100,000

- Sold the Company's interest in the Boltan property for net proceeds of $9.3 million and redeployed the capital in projects at Harmattan, Pouce Coupe and Saxon

- Drilled 23 (16.2 net) wells comprising 10 (7.5 net) oil wells, 8 (5.2 net) gas wells and 5 (3.5 net) dry holes for a 78 % success rate

- Increased net exploration acreage from 20,208 acres to 37,903 and net acreage under option from 10,240 to 22,280 in spite of the divestiture of the Boltan property

- Increased proved plus probable reserves by 11.7% over the previous year (24.4% after considering the reserves related to the sale of the Boltan property)



FINANCIAL AND OPERATING
3 Months Ended December 31,
----------------------------------------------------------------------------
$ Thousands except for
production/day, $/unit
and number of wells %
drilled information 2006 2005 Change
Total revenue 10,735 13,200 (19)%
Cash flow from operations (1)
Total 4,742 6,991 (32)%
Per share basic .31 .46 (33)%

Net income
Total 257 2,546 (90)%
Per share basic .02 .17 (88)%
Per share diluted .02 .15 (87)%

Common shares outstanding 16,497,402 15,232,936 8%
Net debt including
working capital ($) 40,196 27,862 44%
Operational:
Sales 10,736 13,200 (19)%
Royalties 2,330 3,854 (40)%
Operating costs 1,553 996 56%
Field Net Back (2) 6,853 8,351 (18)%
Field Net Back/ bbl (2) 25.77 40.76 (37)%
General and Administrative 1,531 1,163 32%
General and administrative $/bbl 5.76 5.70 1%
Volumes :
Natural gas (mcf/d) 10,265 8,810 17%
Oil (bbl/d) 220 224 (2)%
NGL's (bbl/d) 960 523 84%
Total Boe/d 2,890 2,216 30%
Wells Drilled (Gross):
Oil 1 6
Gas 2 2
D&A 1 4
Total 4 12

Capital Expenditures ($) 7,481 13,617


12 Months Ended December 31
----------------------------------------------------------------------------
$ Thousands except for
production/day, $/unit
and number of wells %
drilled information 2006 2005 Change
Total Revenue 39,322 25,845 52%
Cash flow from operations(1)
Total 19,651 13,536 45%
Per share basic 1.28 .89 44%

Net income
Total 3,974 3,285 21%
Per share basic .26 .23 13%
Per share diluted .24 .21 14%

Common shares outstanding 16,497,402 15,232,936 8%
Net debt including
working capital 40,196 27,862 44%
Operational:
Sales 39,322 25,845 52%
Royalties 9,664 6,702 44%
Operating costs 5,090 2,354 116%
Field Net Back(2) 24,568 16,788 46%
Field Net Back/ bbl (2) 26.50 35.83 (26)%
General and administrative 3,358 2,879 17%
General and administrative $/bbl 3.62 6.18 (41)%
Volumes:
Natural gas(mcf/d) 9,310 4,966 87%
Oil(bbl/d) 192 123 56%
NGL's(bbl/d) 796 325 145%
Total Boe/d 2,540 1,276 99%
Wells Drilled(Gross):
Oil 10 22
Gas 8 5
D&A 5 5
Total 23 32

Capital Expenditures($) 42,280 49,962


RESERVES

Accrete has received its updated independent reserve evaluation report, compliant with National Instrument 51-101 from GLJ Petroleum Consultants ('GLJ'). Under NI 51-101, proved reserve assignments are based on a 90 percent certainty that total quantities recovered will equal or exceed proved reserve estimates. Proved plus probable reserves are the most likely case and are based on a 50 percent certainty that they will equal or exceed estimates. The reserves committee of Accrete's board of directors, which is made up of a majority of independent directors, met with GLJ representatives and has reviewed the independent evaluator's reserves report. Summary information is presented below. Additional disclosure, in accordance with NI 51-101, will be provided in the Company's annual information form. Reserves for year-end December 31, 2006 are as follows:



Total Proved Reserves (Company Interest)

Gas Oil Heavy Oil NGL's BOE NPV ($M)
(bcf) (mbbls) (mbbls) (mbbls) (mbbls) 8% 10%
December 31, 2005 23.29 0.9 0 1969.0 5852 121836 114550
Revisions 0.35 342.8 0 151.5 553.4 - -
Drilling Discoveries 1.36 0 0 41.8 269.2 - -
Drilling Extensions 5.13 162.2 0 477.8 1494.6 - -
Acquisitions .87 17.3 0 99.9 261.5 - -
Divestitures -2.99 0 0 -22.1 -521.4 - -
Production -3.23 -88.6 0 -288.9 -914.5 - -
----------------------------------------------------------------------------
December 31, 2006
Closing 24.78 434.6 0 2430.5 6994.8 125274 116341


Total Proved plus Probable Reserves (Company Interest)

P&P
Gas Oil Heavy Oil NGL's BOE NPV ($M)
(bcf) (mbbls) (mbbls) (mbbls) (mbbls) 8% 10%
December 31, 2005
Opening 34.67 1.6 0 2990 8770 156641 145182
Revisions -0.59 510.6 0 52.4 463.6 - -
Drilling Discoveries 2.59 - 0 66.8 498.9 - -
Drilling Extensions 4.94 313.0 0 407.6 1543.5 - -
Acquisitions 1.08 23.1 0 125.9 329.2 - -
Divestitures -5.14 - 0 -37.6 -894.1 - -
Production -3.22 -88.6 0 -288.9 -914.4 - -
----------------------------------------------------------------------------
December 31, 2006
Closing 34.32 759.7 0 3316.4 9796.6 163159 149596

NOTE: Due to number rounding and conversions, some values are approximate.
NPV values are based on GLJ January 1, 2007 price forecast.


The reconciliation and comparisons outlined above reflect current proved plus probable reserves versus previous proved plus probable reserves as carried by Accrete at December 31, 2005 as determined by GLJ. Investors should note that boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Total Proved plus Probable Reserves have increased 11.7% from December 31, 2005 from 8770 MBOE to 9797 MBOE. This increases to 24.4% when the sale of the Boltan reserves is considered. Total Proved Reserves increased 19.5% over the same period, from 5852 MBOE to 6995 MBOE. Proved Producing Reserves account for 5992 MBOE or 85.7% of the Total Proven Reserve base. Proved Non-Producing volumes are 600 MBOE or 8.6% of the Total Proven Reserve base. It is expected that Proved Non Producing reserves will be placed on production by mid to end of the 2nd Quarter as tie-ins are completed. Proven Undeveloped Reserves account for 5.8% of the Total Proven Reserve base.

A second opinion on the reserves determination of Harmattan was sought from another independent reserve evaluator. As this property is the single biggest component of the Company's value (83%) this second opinion, as done by AJM Petroleum Consultants ("AJM"), was a means of validating the Company's expectation of the property. The Report was created as per NI 51-101 and the COGE Handbook guidelines and resulted in 58.0 MBOE (Proved) and 835 MBOEs (Proved & Probable) additional reserves for the Harmattan property. The difference in the P&P volumes reflects the recognition of the current maturity of the wells and the expected long-term performance. In utilizing these additional values the Company's reserves would become 7059.2 MBOE Proven and 10658 MBOE Proven & Probable. This would have a corresponding effect on the Company's F&D costs whereby the values would be reduced by the inclusion of the additional volumes recognized by the AJM report (approximately $4.00/BOE).

The above reserves, after production is considered, results in total additions for the year of 2.83 MMBOE's (3.67 MMBOE's AJM adjusted). This results in Finding and Development (F&D) costs as outlined in the Table below.



Total Proved Total Proved & Probable

GLJ AJM Adjusted GLJ AJM Adjusted
----- -------------- ----- --------------

Reserve Additions (MBOE's) 2573 2631 2830 3665
Capital ($MM) 51.27 51.27 51.27 51.27
Future Dev Capital ($MM) 3.595 2.78 11.255 13.26
F&D W/O FDC ($/BOE) 19.93 19.49 18.12 13.99
F&D W/ FDC ($/BOE) 21.32 20.54 22.09 17.61

NOTE: AJM adjusted utilizes the changes as would be seen utilizing the AJM
report combined with the GLJ report.


MANAGEMENT DISCUSSION AND ANALYSIS

The following discussion and analysis was prepared on March 19, 2007 and is management's assessment of Accrete's historical financial and operating results and should be read in conjunction with the audited financial statements and related notes for the years ended, December 31, 2006 and 2005.

The financial data presented has been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The reporting and measurement currency is the Canadian dollar.

Additional information may be found on the Company's web site at www.accrete-energy.com and on the SEDAR web site at www.sedar.ca.

Accrete was established on June 1, 2004 and is a Calgary based, natural gas focused exploitation and development company that operates exclusively in Alberta.

It has production in the Harmattan, Edson and Claresholm areas and Pouce Coupe of Alberta. It has developed a focused inventory of drilling prospects at Harmattan, Claresholm, Ansell, Saxon and Pouce Coupe.

Accrete's shares trade on the Toronto Stock Exchange ("TSX") under the symbol GZ.

Business Environment

Apart from a spike in pricing during a short lived summer heat wave, moderate temperatures prevailed during 2006. The hurricane season was mostly a non event in North America in 2006. Consequently, fears that supply would significantly outstrip demand caused the weighted average AECO NGX next day index prices to decline from a high of $8.10/Gj in January to a low of $4.66/Gj in September. Prices rose with a cold snap in November to average $7.41/Gj and settled back to average $6.57 for December as the colder weather abated.

On the oil front, supply concerns brought about by geopolitical conditions overseas caused Edmonton Par price for oil to increase to a peak of $85.47/Bbl in July before retreating to $71.18/Bbl in September as those concerns eased.

Operating and finding and on-stream costs relentlessly crept upwards as the market prices of goods and services used in the industry increased.

The decision by our current federal government to enact changes to the tax structure of Income Trusts has caused a great deal of uncertainty and confusion in the minds of both the Industry and the Market.



Financial Information

Total Revenue Net Income Net Income Net Income
($ thousands) ($ thousands) Basic $/Share Diluted $/Share
----------------------------------------------------------------------------
2006

First Quarter 9,821 1,584 0.10 0.10
Second Quarter 9,183 1,390 0.09 0.08
Third Quarter 9,584 743 0.05 0.05
Fourth Quarter 10,734 257 0.02 0.01
Total 39,322 3,974 0.26 0.24

2005

First Quarter 3,633 707 0.05 0.05
Second Quarter 2,954 (818) (0.06) -
Third Quarter 6,058 850 0.06 0.05
Fourth Quarter 13,200 2,546 0.17 0.16
Total 25,845 3,285 0.23 0.21


Production for the fourth quarter 2006 averaged 2,890 BOE/Day. This increase was attributable to drilling in the period and the tie in of wells drilled earlier in the year. The increase would have been larger had the Company not shut in wells in the Harmattan area in order to complete additional zones. This recompletion program continued into the first quarter of 2007.

Fourth quarter revenue, however was negatively impacted by the fact that prices that were received for petroleum and natural gas sales in 2006 were significantly less than in 2005. Natural gas prices averaged $11.70 per mcf in 2005 whilst only averaging $7.18 per mcf in 2006. The average price received for oil in the third quarter 2005 was $69.13 as opposed to $53.86 in 2006. Natural gas liquids prices averaged $46.75 in 2005 and $31.94 in 2006.

In spite of the Company's best efforts to control costs, the scarcity of oilfield supplies and services led to an increase in field costs from $4.88 per bbl equivalent in 2005 to $5.84 per bbl equivalent in 2006.

As a result of lower product prices and increased field costs, field netbacks for the fourth quarter decreased from $40.76 in 2005 to $25.77 in 2006.

Increased volumes as noted above, partially offset the negative impact of lower product prices and higher costs.

General and administrative expenses were higher in the fourth quarter of 2006 than in 2005 because of increased staffing levels and lower recoveries from charges to participants on capital projects. The combination of lower prices, increased costs and increased general and administrative expenses led to a decrease in the corporate netback from fourth quarter production from $35.19 per bbl in 2005 to $20.19 in 2006.

Adjustments that were made in the fourth quarter 2006 to the Company's tax provision, further contributed to the decrease in net income.

During the fourth quarter 2006 the Company drilled 4 wells (2.8 net) comprising 1 (.54 net) oil wells, 2 (1.3 net) gas wells and 1 (1 net) dry hole. A success rate of 75% was achieved.

During the twelve months ended December 31, 2006, the Company drilled a total of 23 wells (16.2 net), comprising 10 (7.5 net) oil wells, 8 (5.2 net) gas wells and 5 (3.5 net) dry holes.

The Company estimates that at December 31, 2006 that behind pipe are 484 net barrels of oil equivalent per day. This is comprised of 176 barrels at Harmattan, 83 barrels at Saxon, 50 barrel at Claresholm and 175 barrels at Pouce Coupe.



Operational Activities

Production
3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Oil (bbl/d) 220 224 192 123
NGL (bbl/d) 960 523 796 325
----------------------------------------------------------------------------
Total Oil/NGL (bbl/d) 1,180 747 988 448
Gas (mcf/d) 10,265 8,810 9,310 4,966
----------------------------------------------------------------------------
Total (boe/d) 2,890 2,216 2,540 1,276
----------------------------------------------------------------------------

Natural Gas Production
(mcf/d)
3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area
Atlee-Buffalo 26 43 26 79
Boltan - 644 153 528
Claresholm 2,653 3,486 3,186 1,389
Harmattan 7,206 4,637 5,849 2,970
Edson 380 - 96 -
----------------------------------------------------------------------------
Total 10,265 8,810 9,310 4,966
----------------------------------------------------------------------------

Crude Oil Sales (bbl/d)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area
Atlee-Buffalo - - - -
Boltan - - - -
Claresholm - 33 - 10
Harmattan 214 191 191 113
Edson 6 - 1 -
----------------------------------------------------------------------------
Total 220 224 192 123
----------------------------------------------------------------------------

Natural Gas Liquids Sales (bbl/d)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area
Atlee-Buffalo - - - -
Boltan 1 2 1 3
Claresholm 10 23 38 8
Harmattan 941 498 755 314
Edson 8 - 2 -
----------------------------------------------------------------------------
Total 960 523 796 325
----------------------------------------------------------------------------


The increase in production levels are a result of the Company's drilling activity offset in part by natural declines, the loss of production resulting from the sale of the Boltan property and the shut in of certain Harmattan wells to facilitate recompletion of additional zones.



Product Prices

Natural Gas Prices ($/mcf)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area
Atlee-Buffalo 5.65 10.82 6.78 7.82
Boltan - 11.26 7.89 8.81
Claresholm 7.60 12.37 7.38 11.18
Harmattan 6.99 11.26 6.56 9.51
Edson 7.83 - 7.83 -
----------------------------------------------------------------------------
Average Price 7.18 11.70 6.88 9.87
----------------------------------------------------------------------------

Crude Oil Sales Prices ($/bbl)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area
Atlee-Buffalo - - - -
Boltan - - - -
Claresholm - 68.52 - 69.86
Harmattan 53.74 69.24 69.57 70.26
Edson 58.87 - 58.87 -
----------------------------------------------------------------------------
Average Price 53.86 69.13 69.49 70.23
----------------------------------------------------------------------------

Natural Gas Liquids (NGL) Sales Prices ($/bbl)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area
Atlee-Buffalo - - - -
Boltan 48.13 59.46 55.34 62.13
Claresholm 21.54 69.38 69.10 71.59
Harmattan 31.87 45.63 35.30 38.42
Edson 48.41 - 48.41 -
----------------------------------------------------------------------------
Average Price 31.94 46.75 36.98 39.50
----------------------------------------------------------------------------

The Company has not entered into any hedging arrangements with respect to
the sale of its production in 2005 or 2006.

Subsequent to year-end, the Company entered into the following contracts:

Type Amount Term Price ($/GJ) Type
----------------------------------------------------------------------------
Collar 2,000GJ/d February 1- $5.50 - $8.25 at AECO Financial
October 31, 2007
Collar 2,000GJ/d March 1 - $5.50 - 9.13 at AECO Financial
October 31, 2007


Natural gas prices rose during 2005 reaching peak levels by the end of the year. Prices declined from that point during 2006 and aside from a small rally due to a heat wave in August, prices slid downwards to a low in September. A cold snap in November caused prices to rise sharply but they tailed off about 10% in December as warmer weather was forecast.

Normally Claresholm gas commands a higher price because it includes ethanes that give it a higher heating content. The Boltan property was sold early in the second quarter when pricing was higher than it was for the remainder of the period.

The trend set by world oil prices is reflected in the crude oil price realized by Accrete.

At Harmattan, NGLs comprise a considerable portion of ethanes which are relatively low priced.



Revenue

Total Sales

($ thousands)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Oil 1,089 1,427 4,877 3,160
NGL 2,820 2,259 10,746 4,700
Gas 6,778 9,481 23,363 17,898
Processing 49 33 336 87
----------------------------------------------------------------------------
Total 10,736 13,200 39,322 25,845
----------------------------------------------------------------------------

Natural Gas Sales Revenue

($ thousands)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area
Atlee-Buffalo 13 43 64 227
Boltan - 667 439 1,697
Claresholm 1,856 3,969 8,584 5,667
Harmattan 4,636 4,802 14,003 10,307
Edson 273 - 273 -
----------------------------------------------------------------------------
Total 6,778 9,481 23,363 17,898
----------------------------------------------------------------------------

Crude Oil Sales Revenue

($ thousands)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area
Atlee-Buffalo - - - -
Boltan - - - -
Claresholm - 213 - 249
Harmattan 1,059 1,214 4,848 2,911
Edson 30 - 29 -
----------------------------------------------------------------------------
Total 1,089 1,427 4,877 3,160
----------------------------------------------------------------------------

Natural Gas Liquids (NGL) Sales Revenue

($ thousands)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area
Atlee-Buffalo - - - -
Boltan 8 25 39 80
Claresholm 19 141 949 211
Harmattan 2,758 2,093 9,723 4,409
Edson 35 - 35 -
----------------------------------------------------------------------------
2,820 2,259 10,746 4,700
----------------------------------------------------------------------------

Processing Revenue

($ thousands)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area
Atlee-Buffalo - - - -
Boltan - - - -
Claresholm - (4) - 17
Harmattan 49 37 336 70
Edson - - - -
----------------------------------------------------------------------------
Total 49 33 336 87
----------------------------------------------------------------------------


The increase in revenue occurred primarily because of the addition of production from new wells. These gains were offset in part by natural declines, the decline in commodity prices, the loss of production from the sale of the Boltan area, the shut in of the Harmattan processing facility in September, as well as the intermittent shut in of some Harmattan wells in order to complete additional zones.

Processing fees are charged to third parties utilizing Accrete facilities.



Royalties

($ thousands)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area Total $ Rate Total $ Rate Total $ Rate Total $ Rate
----------------------------------------------------------------------------
Atlee-Buffalo 1 6% 5 11% 9 15% 36 18%
Boltan 0 0% 57 8% 42 9% 150 8%
Claresholm 248 13% 1,184 27% 2,260 24% 1,571 26%
Harmattan 1,972 23% 2,608 32% 7,244 26% 4,945 28%
Edson 109 32% - - 109 32% - -
----------------------------------------------------------------------------
Total 2,330 22% 3,854 29% 9,664 26% 6,702 26%
----------------------------------------------------------------------------


Crown royalties, net of Alberta Royalty Tax Credit, were $1,480,042 for the fourth quarter 2006 and $7,244,018 for the year ended December 31, 2006. Total gross overriding royalties were $757,933 and $2,041,946 respectively, and freehold royalties totalled $92,186 and $378,201 respectively. The Company had reached the maximum allowable ARTC early in the second quarter 2006. From that point onward in 2006, no further credits are available. The apparent reduction in rate at Harmattan in 2006, occurs because a greater proportion of freehold wells bearing a relatively lower royalty rate were put on stream.

Atlee Buffalo production is subject to low rates for shallow low productivity wells.

Boltan production enjoyed a deep gas crown royalty holiday and was subject only to gross overriding royalties on production.



Production and Transportation Expenses

($ thousands except per boe information)

3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Area $ $/boe $ $/boe $ $/boe $ $/boe
Atlee-Buffalo 7 16.73 4 5.84 24 14.95 57 11.74
Boltan 9 - 129 12.55 197 19.76 268 8.03
Claresholm 346 8.34 273 4.65 1,329 6.40 413 4.54
Harmattan 1,087 5.01 590 4.39 3,436 4.90 1,616 4.80
Edson 104 14.79 - - 104 14.79 - -
----------------------------------------------------------------------------
Total 1,553 5.84 996 4.88 5,090 5.49 2,354 5.05
----------------------------------------------------------------------------


Atlee Buffalo is a very small part of the overall operation and although operating costs are high, the effect on total expenses is minimal.

Claresholm costs reflect bulk purchases of supplies in the fourth quarter.

The industry as a whole was challenged by a scarcity of supply of services and increasing prices that result. Costs in general increased in spite of the Company's best efforts to manage them.



Field and Corporate Netbacks

Field Netback



($/boe) 3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
Area 2006 2005 2006 2005
----------------------------------------------------------------------------

Atlee-Buffalo 15.07 53.65 19.72 28.25
Boltan - 49.98 23.92 40.93
Claresholm 30.82 49.13 28.64 45.77
Harmattan 25.14 36.79 26.02 33.10
Edson 17.64 - 17.64 -
----------------------------------------------------------------------------
Field Netback 25.77 40.76 26.50 35.83
----------------------------------------------------------------------------

Field net backs basically reflect the effect of lower product prices for
natural gas, increasing pressure on operating costs, offset in part by lower
royalty rates.

Corporate Netback

($ thousands) 3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
Area 2006 2005 2006 2005
----------------------------------------------------------------------------
Field Netback 6,851 8,350 24,568 16,788
General and
Administrative 1,531 1,163 3,358 2,879
----------------------------------------------------------------------------
Corporate Netback 5,320 7,187 21,210 13,909
----------------------------------------------------------------------------


Corporate netback decreased with the decrease in field netbacks as noted previously, as well as with increases in general and administrative expenses.



General and Administrative Expense

($ thousands) 3 Months 3 Months 12 Months 12 Months
Ended Ended Ended Ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
----------------------------------------------------------------------------
Salary & Benefits 1,329 1,141 2,853 2,524
General Office Expenses 381 368 1,425 1,248
----------------------------------------------------------------------------
1,710 1,509 4,278 3,772
Recoveries (179) (346) (920) (893)
----------------------------------------------------------------------------
Total 1,531 1,163 3,358 2,879
----------------------------------------------------------------------------


The Company has increased staffing levels over the past year and now employs 17 people.

Office expenses increased with inflationary pressure.

General and administrative expenses are recovered through billings to participants in company operated projects in accordance with standard industry practice. The increase in recoveries year over year relates to the increase in capital expended on capital projects. The decrease in the fourth quarter recovery amounts relates to the fewer plant and facility costs in 2006 compared to 2005, and the associated recoveries with that type of capital.

Interest Expense

At December 31, 2006, Accrete's bank indebtedness was $36.4 million. Accrete utilized its operating line of credit and cash flow to fund its 2006 capital program. As a result, interest expense of $578,000 was incurred in the forth quarter of 2006 and $1,559,000 was incurred for the twelve months ended December 31, 2006.

Stock-Based Compensation

Stock-based compensation is accounted for using the fair value method. Under the fair value method of accounting, this compensation expense is recorded in the earnings statement over the vesting period. In the second quarter of 2005, Accrete recognized options previously disclosed but deemed to be not granted until the Annual General Meeting was held on May 5, 2005. This retroactive granting led to an abnormal period cost, with a large retroactive component to it.

Depletion Depreciation & Accretion

Depletion, depreciation and accretion of the asset retirement obligation for the three and twelve month period ended December 31, 2006 totalled $3,610,000 or $13.58/Boe, and $12,966,000 or $13.99/Boe respectively. Costs of $4,045,000 relating to unproved properties have been excluded from costs subject to depletion for the 3 month period ended December 31, 2006. This included the costs of undeveloped land such as that at Ansell, Saxon and Pouce Coupe that has been purchased at land sales for future exploitation.

Income Taxes

The Company is not liable for any cash taxes. Adjustments were made in the fourth quarter 2006, to reflect the rescheduling of the reversals of timing differences and to true up the Company's future taxes for tax returns filed.

Cash Flow

Cash flow from operations for the three months ended December 31, 2006 was $4,742,000 ($0.31 per share) and $19,651,000 ($1.28 per share) for the twelve months ended December 31, 2006.



Capital Expenditures

Capital expenditures for the twelve months ending December 31, 2006:

($ thousands) 12 Months 3 Months 3 Months 3 Months 3 Months
Ended Ended Ended Ended Ended
December December September June March
31, 2006 31, 2006 30, 2006 30, 2006 31, 2006
--------------------------------------------------------
$ $ $ $ $
--------------------------------------------------------
Drilling and
Completions 37,578 5,577 13,439 10,109 8,453
Equipping and
Tie-Ins 3,392 499 733 1,269 891
Land 4,253 1,362 1,457 3 1,431
Property
Acquisitions and
Dispositions (net) (3,300) - 6,043 (9,343) -
Office Equipment 4 1 - - 3
----------------------------------------------------------------------------
Total Cash
Expenditures 41,927 7,439 21,672 2,038 10,778
Allowance for future
restoration
expenditures 352 41 103 72 136
----------------------------------------------------------------------------
Total 42,279 7,480 21,775 2,110 10,914
----------------------------------------------------------------------------


During the fourth quarter the Company drilled 4 wells (2.8 net), comprising 1(.54 net) oil well, 2(1.3 net) gas wells and 1 (1 net) dry hole. A success rate of 75% was achieved. For the year, the Company has drilled 23 wells (16.2 net), comprising 10 (7.5 net) oil wells, 8 (5.2 net) gas wells and 5 (3.5 net) dry holes.

The Company completed the expansion of its compression facilities at Harmattan.

The Company's interests in the Boltan area were disposed early in the second quarter 2006 because it no longer met the Company's long term objectives.



Liquidity and Capital Resources

$ (thousands)
--------------
2006 Exploration and development program funding
Cash, Beginning of Year -
Cash flow from operations 19,651
Change in non-cash working capital (9,441)
Increase in Bank Debt 21,825
Funds from Stock Issuance 9,892
Cash, end of period -
--------------
Net capital expenditures 41,927
--------------


During the fourth quarter of 2006, the corporation issued 1,248,300 common flow-through shares at an issuance price of $8.40 per share for net proceeds of $9,982,000. The corporation is committed to spend $10,486,000 on CEE expenditures to fulfil its flow-through obligation. Qualifying expenditures will primarily be made and renounced in the first quarter of 2007.

Accrete intends to fund its capital expenditure program from internally generated cash flow, debt, and new equity.

At December 31, 2006 the Company's credit facility comprises a Revolving Operating Demand Loan facility with a credit limit of $50,000,000.

This facility bears interest at bank prime plus one eighth percent and has no specific terms of repayment aside from the bank's right of demand and periodic review.

The capital intensive nature of the Company's activities may create a negative working capital position from time to time and, in fact, at December 31, 2006, negative working capital, including bank debt was $40,196,000.

Success in its focus areas means that additional funds will be raised through additional bank debt or additional share issuances or both to expedite or expand the drilling program.

Commodity prices and production volumes have a large impact on the ability of the Company to generate adequate cash flow. A prolonged decrease in commodity prices would negatively affect cash flow from operations and would also likely result in a reduction in the amount of cash flow and bank loan available for investment. This condition may also affect the availability of funds through the public equity market which may be accessed if funds are available on favourable terms.

See the caption entitled "Risks" for further items that could affect liquidity.

Outlook

The Company will maintain sufficient activity to stabilize production at Harmattan and Claresholm and will utilize the cash flow generated to develop its inventory of prospects at Ansell, Pouce Coupe and Saxon.

The Company will continue to seek opportunities in new areas so as to provide future development opportunities.

Critical Accounting Estimates

Oil and Gas Accounting

The Company follows the full-cost method of accounting whereby all costs related to the acquisition, exploration and development of petroleum and natural gas properties, net of government incentives, are capitalized. Such costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling both productive and non-productive wells and related plant and production equipment costs.

Proceeds on disposition of petroleum and natural gas properties are accounted for as a reduction of capitalized costs with no gains or losses recognized unless such disposition results in a change of 20% or more in the depletion rate.

Capitalized costs, together with estimated future capital costs associated with proved reserves are depleted and depreciated using the unit-of-production method based on estimated gross proved reserves of petroleum and natural gas as determined by independent engineers. For purposes of this calculation, reserves and production are converted to equivalent units of oil based on the relative energy content of six thousand cubic feet of natural gas to one barrel of oil. Unproved properties are excluded from the depletion base until it is determined whether proved reserves are attributable to the properties or impairment occurs.
The net amount at which petroleum and natural gas properties are carried is subject to a cost recovery test (the "ceiling test").

Oil and gas assets are evaluated at least annually to determine that the costs are recoverable and do not exceed the fair value of the properties. The costs are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost and market of unproved properties exceed the carrying value of the oil and gas assets. If the carrying value of the oil and gas assets is not assessed to be recoverable, an impairment loss will be recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves and the lower of cost or market value unproved properties. The cash flows are estimated using future product prices and costs and are discounted using the risk free rate.

The Company records a liability for the fair value of legal obligations associated with the retirement of long-lived assets in the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability, there is a corresponding increase in the carrying amount of the related asset known as the asset retirement cost which is depleted using the unit-of- production method. The liability is adjusted in each reporting period to reflect the passage of time, with the accretion charged to earnings, and for revisions to the estimated future cash flows.

Income Taxes

The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after a considerable lapse of time. Accordingly, the actual income tax liability may differ significantly from the liability estimated or recorded.

Other Estimates

The accrual method of accounting requires management to incorporate certain estimates, including estimates of revenues, royalties and production costs at a specific reporting date but for which actual revenues and costs have not yet been received; and estimates on capital projects which are in progress or recently completed where actual costs have not been received at a specific reporting date.

The Company ensures that the individuals with the most knowledge of the activity are responsible for the estimate. These estimates are then reviewed for reasonableness and past estimates are compared to actual results in order to make informed decisions on future estimates.

Stock Based Compensation

The Company has not incorporated an estimated forfeiture rate for stock options that will not vest and will account for actual forfeitures as they occur. The fair value of each stock option is determined at each grant date using the Black-Scholes model.

Risks

Accrete, in common with other companies participating in the oil and gas business in Canada, is exposed to a number of business risks. These risks can be categorized as operational, financial and regulatory, with some beyond the Company's control.

Operational risks include finding and developing oil and natural gas reserves on an economic basis, reservoir production performance, commodity marketing risk and the risk that employees and contract services can be hired and retained on a cost effective basis.

Accrete has mitigated these risks to the extent possible by employing a team of highly qualified professionals, providing a compensation scheme that will reward above average performance and by maintaining long term relationships with its suppliers.

Accrete also maintains an insurance program that is consistent with industry practice that should protect against the loss of assets through fire, blowout, pollution and other untoward events and the resultant business interruption.

Accrete maintains an inventory of prospects that are within the scope of the Company's key areas and are strategically diverse so as to minimize the Company's exposure to drilling risk. Furthermore, Accrete employs the latest technological methods in that quest.

Commodity prices and production volumes have a large impact on the ability for the Company to generate adequate cash flow to meet its obligations. A prolonged decrease in commodity prices would negatively affect cash flow from operations and would also likely result in a reduction in the amount of bank loan available. If the capital expenditure program does not result in sufficient additional reserves and/or production it would likely have a negative impact on the Company's liquidity. A lack of, or restricted access to natural gas processing facilities would have a similar effect. A prolonged decrease in commodity prices would also likely affect the availability of funds through the public equity market.

Financial risks include commodity prices, and to some extent, interest rates and the Canadian/US exchange rate. The Company may employ financial instruments, when prudent, to lessen the effects of such risks, but it has no such contracts in place at this time.

Exploration, Development and Production Risks

Oil and natural gas exploration involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that expenditures made on future exploration by Accrete will result in new discoveries of oil or natural gas in commercial quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

The long-term commercial success of Accrete depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. No assurance can be given that Accrete will be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, Accrete may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.

Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated, and can be expected to adversely affect revenue and cash flow levels to varying degrees.

In addition, oil and gas operations are subject to the risks of exploration, development and production of oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence of any of these risks could have a materially adverse effect on Accrete and its future results of operations, liquidity and financial condition.

Income Taxes

The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded.

Disclosure Controls and Internal Controls Over Financial Reporting

The Company has implemented a system of internal controls that it believes adequately protects the assets of the Company and is appropriate for the nature of its business and the size of its operations. These internal controls include disclosure controls and procedures designed to ensure that information required to be disclosed by the Company is accumulated and communicated to our management as appropriate to allow timely decisions regarding required disclosure. The CEO and CFO have evaluated the effectiveness of the Company's disclosure controls and procedures as defined in Multilateral Instrument 52-109 (Certification of Disclosure in Issuers' Annual and Interim Filings) of the Canadian Securities Administrators and have concluded based on their evaluation that as of December 31, 2006, that such controls and procedures are effective to provide reasonable assurance that material information related to the Company is made known to them.

The Chief Executive Officer and Chief Financial Officer of the Company are responsible for designing internal controls over financial reporting or causing them to be designed under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian Generally Accepted Accounting Principles.

The Chief Executive Officer and Chief Financial Officer of the Company have conducted an evaluation which has identified an inherent weakness in the system of internal control over financial reporting that is due to the limited number of staff at the Company. Namely, it is not economically feasible to achieve complete segregation of duties. As a result of this weakness, there is no guarantee that a material misstatement would not be prevented or detected. Management and Board review are utilized to mitigate the risk of material misstatement in financial reporting to ensure internal controls remain effective. Additional accounting staff will be added as the Company grows and this is expected to remediate the weakness.

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 and internal controls over financial reporting provide a reasonable level of assurance that the system of internal controls are effective, they do not guarantee 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.

Commitments

Pursuant to flow-through share offerings during the year ended December 31, 2006, the Company is committed to incur a total of $10,485,720 in qualifying expenditures by December 31, 2008.

The Company has entered into various commitments related to the leasing of office premises and office equipment. The payments due under such leases are as follows:



Contractual obligations 2007 2008 2009 2010 2011 Thereafter
($ thousands) $ $ $ $ $ $
----------------------------------------------------------------------------

Office Premises 189 47 - - - -
Office equipment 9 2 1 - - -
198 49 1 - - -


Change in Accounting Policies and Recent Accounting Pronouncements

The following standards regarding financial instruments are effective for January 1, 2007; 3855 - "Financial Instruments - Recognition and Measurement", 3861 Financial Instruments - Disclosure and Presentation, 1530 - "Comprehensive Income", and 3865 - "Hedges". The standards require all financial instruments other than held-to-maturity investments, loans and receivables, to be included on a company's balance sheet at their fair value. Held-to-maturity investments, loans and receivables would be measured at their amortized cost. The standards create a new statement for comprehensive income that will include changes in the fair value of certain derivative financial instruments. As a result of these new standards, the Company expects not to elect to use hedge accounting beginning January 1, 2007 and will mark-to- market its natural gas derivative contracts under its risk management program. The accounting for hedging relationships for prior fiscal years is not retroactively changed, therefore, no restatement of prior periods is expected as a result of these new standards.

Transactions With Related Parties

The Corporation has not entered into any transactions with related parties, nor did it have any balances outstanding with related parties at year end.

Off Balance Sheet Arrangements

The Corporation has not entered into any off-balance sheet transactions.

Non GAAP Measures

The forgoing contains the term "cash flow from operations" and "netbacks" which should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with Canadian Generally Accepted Accounting Principles ("GAAP") as an indicator of the Company's performance. Accrete's definition of cash flow from operations and/or netbacks may not be comparable to that reported by other companies.

The Company evaluates its performance based on net earnings, net back and cash flow. The Company considers cash flow a key measure as it illustrates the Company's ability to meet obligations necessary to repay debt and fund future growth through capital investment. Cash flow per share is presented in this discussion using the weighted average shares outstanding in a manner consistent with that used to calculate earnings per share.

The following table reconciles cash flow from operating activities, the most comparable GAAP measure to cash flow used in this MD&A:



Year Ended
$ Thousands December 31, 2006 December 31, 2005
----------------------------------------------------------------------------
Cash flow provided by operating
activities 17,527 12,671
Net changes in non-cash working capital 2,124 865
Cash flow 19,651 13,536

The following table reconciles field and corporate netback to income before
taxes the most comparable GAAP measure:

Year Ended
$ Thousands December 31, 2006 December 31, 2005
----------------------------------------------------------------------------
Income before income taxes 5,864 5,839
Depletion, depreciation and accretion 12,966 5,511
Stock based compensation cost 821 2,236
Interest expense 1,560 323
Corporate netback 21,210 13,909
General and administrative expenses 3,358 2,879
Field netback 24,568 16,788


The reader is cautioned that the use of the term boe's ("barrels of oil equivalent") may be misleading particularly when used in isolation. A boe conversion of 6 mcf to 1 boe may not represent a value equivalency at the wellhead.

As the determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these financial statements requires the use of estimates and assumptions which have been made using careful judgement. In the opinion of management, the unaudited interim financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized in the financial statements.

Disclaimers

Some of the statements contained herein including, without limitation, financial and business prospects and financial outlooks may be forward-looking statements which reflect management's expectations regarding future plans and intentions, growth, results of operations, performance and business prospects and opportunities. Words such as "may", "will", "should", "could", "anticipate", "believe", "expect", "intend", "plan", "potential", "continue" and similar expressions have been used to identify these forward-looking statements. These statements reflect management's current beliefs and are based on information currently available to management. Forward-looking statements involve significant risk and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements including, but not limited to, changes in general economic and market conditions and other risk factors. Although the forward-looking statements contained herein are based upon what management believes to be reasonable assumptions, management cannot assure that actual results will be consistent with these forward-looking statements. Investors should not place undue reliance on forward-looking statements. These forward-looking statements are made as of the date hereof and we assume no obligation to update or revise them to reflect new events or circumstances.

Forward-looking statements and other information contained herein concerning the oil and gas industry and Accrete's general expectations concerning this industry are based on estimates prepared by management using data from publicly available industry sources as well as from reserve reports, market research and industry analysis and on assumptions based on data and knowledge of this industry which Accrete believes to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While Accrete is not aware of any misstatements regarding any industry data presented herein, the industry involves risks and uncertainties and is subject to change based on various factors.



FINANCIAL STATEMENTS

Accrete Energy Inc.
Balance Sheets

----------------------------------------------------------------------------
($ Thousands) December 31, December 31,
2006 2005
$ $
----------------------------------------------------------------------------

ASSETS

Current assets
Accounts receivable 7,421 8,221
Prepaid expenses 131 64
----------------------------------------------------------------------------
7,552 8,285
Property and equipment (note 2) 95,506 66,083
----------------------------------------------------------------------------
103,058 74,368
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Current liabilities
Accounts payable and accrued liabilities 11,325 21,549
Bank indebtedness (note 3) 36,423 14,598
----------------------------------------------------------------------------
47,748 36,147

Asset retirement obligation (note 5) 1,663 1,152
Future income tax (note 6) 4,773 3,091
----------------------------------------------------------------------------
54,184 40,390
----------------------------------------------------------------------------
Share capital (note 4) 39,718 29,618
Contributed surplus (note 4) 3,415 2,593
Retained Earnings 5,741 1,767
----------------------------------------------------------------------------
48,874 33,978
----------------------------------------------------------------------------
103,058 74,368
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to financial statements

Accrete Energy Inc.
Statements of Income and Retained Earnings

($ Thousands) Year Year
Ended Ended
December 31, December 31,
2006 2005
----------------------------------------------------------------------------
Revenue $ $
Petroleum and natural gas revenue 39,322 25,845
Royalties (net of Alberta Royalty Tax Credit) (9,664) (6,702)
----------------------------------------------------------------------------
29,658 19,143
----------------------------------------------------------------------------

Expenses

Production expenses 4,724 2,163
Transportation expenses 366 192
General and administrative, net of recoveries 3,358 2,879
Interest Expense 1,559 323
Stock based compensation cost (note 4) 821 2,236
Depletion, depreciation and accretion 12,966 5,511
----------------------------------------------------------------------------
23,794 13,304
----------------------------------------------------------------------------
Income before income taxes 5,864 5,839
Future income taxes (note 6) (1,890) (2,553)
----------------------------------------------------------------------------
3,974 3,286
Net income for the period
Retained Earnings (Deficit) - beginning of year 1,767 (1,519)
----------------------------------------------------------------------------
Retained Earnings - end of year 5,741 1,767
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average number of shares (note 4) 15,326 14,329
Income per share:
Basic 0.26 0.23
Diluted 0.24 0.21



See accompanying notes to financial statements

Accrete Energy Inc.
Statements of Cash Flows
($ Thousands)
Year Year
Ended Ended
December 31, December 31,
2006 2005
----------------------------------------------------------------------------
Cash provided by (used in): $ $
Operating Activities
Net income for the period 3,974 3,286
Items not affecting cash:
Stock based compensation cost 821 2,236
Future income taxes 1,890 2,553
Depletion, depreciation and accretion 12,966 5,461
----------------------------------------------------------------------------
19,651 13,536

Change in non-cash working capital (note 8) (2,124) (865)
----------------------------------------------------------------------------
17,527 12,671
----------------------------------------------------------------------------
Investing Activities
Property and equipment additions (45,227) (49,318)
Property Acquisition and Disposition 3,300 -
Change in non-cash working capital (note 8) (7,317) 7,948
----------------------------------------------------------------------------
(49,244) (41,370)
----------------------------------------------------------------------------
Financing Activities
Bank Debt 21,825 14,598
Share Issue Expense, net of tax (668) -
Issue of capital stock 10,560 13,561
----------------------------------------------------------------------------
31,717 28,159
Increase (decrease) in cash - (540)
Cash - beginning of year - 540
----------------------------------------------------------------------------
Cash - end of year - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to financial statements


Accrete Energy Inc.
Notes to the Financial Statements
For the years ended December 31, 2006 and 2005


1. Significant Accounting Policies

As the determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these financial statements requires the use of estimates and assumptions which have been made using careful judgement. In the opinion of management, these financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

Accrete Energy Inc. ("Accrete") commenced operations on June 1, 2004 when it acquired assets under a plan of arrangement entered into by Provident Energy Trust, Provident Energy Ltd., Olympia Energy Inc. and Accrete Energy Inc.

Oil and Gas Operations

Revenues from the sale of petroleum and natural gas are recorded when title passes to an external party.

The Company follows the full-cost method of accounting whereby all costs related to the acquisition, exploration and development of petroleum and natural gas properties, net of government incentives, are capitalized. Such costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling both productive and non-productive wells and related plant and production equipment costs.

Proceeds on disposition of petroleum and natural gas properties are accounted for as a reduction of capitalized costs with no gains or losses recognized unless such disposition results in a change of 20% or more in the depletion rate.

Capitalized costs, together with estimated future capital costs associated with proved reserves are depleted and depreciated using the unit-of-production method based on estimated gross proved reserves of petroleum and natural gas as determined by independent engineers. For purposes of this calculation, reserves and production are converted to equivalent units of oil based on the relative energy content of six thousand cubic feet of natural gas to one barrel of oil. Unproved properties are excluded from the depletion base until it is determined whether proved reserves are attributable to the properties or impairment occurs.

Office furniture and fixtures are recorded at cost and are depreciated over their useful lives on a declining balance basis at 20% per annum.

The net amount at which petroleum and natural gas properties are carried is subject to a cost recovery test (the "ceiling test").

Oil and gas assets are evaluated at least annually to determine that the costs are recoverable and do not exceed the fair value of the properties. The costs are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost and market of unproved properties exceed the carrying value of the oil and gas assets. If the carrying value of the oil and gas assets is not assessed to be recoverable, an impairment loss will be recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves and the lower of cost or market value of unproved properties. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free rate of interest.

The Company records a liability for the fair value of legal obligations associated with the retirement of long-lived assets in the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability, there is a corresponding increase in the carrying amount of the related asset, known as the asset retirement cost, which is depleted using the unit-of- production method. The liability is adjusted in each reporting period to reflect the passage of time, with the accretion charged to earnings, and for revisions to the estimated future cash flows.

Joint Operations

A significant portion of the Company's exploration and production activities are conducted jointly with others and the financial statements reflect only the Company's proportionate interest in such activities.

Stock Based Compensation

The Company has an employee stock option plan. The compensation cost in respect of this plan is recognized in the financial statements using the fair market value method and the cost is recognized over the vesting period of the underlying security. The Company has not incorporated an estimated forfeiture rate for stock options that will not vest and will account for actual forfeitures as they occur.

Measurement Uncertainty

Amounts recorded for depreciation and depletion, the provision for asset retirement and abandonment costs and amounts used for ceiling test calculations are based on estimates of oil and natural gas reserves. The Company's reserve estimates are reviewed annually by an independent engineering firm. By their nature, these estimates of reserves and future cash flows are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material.

Per Share Amounts

The Company uses the treasury stock method to determine the dilutive effect of stock options and other dilutive instruments. This method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to purchase common shares at the average market price during the year.

Flow through Shares

The resource expenditure deductions for income tax purposes related to exploratory and development activities funded by flow through share arrangements are renounced to investors in accordance with income tax legislation. Future income tax liabilities and share capital are adjusted by the estimated cost of the renounced income tax deductions when the related flow through expenditures are renounced to investors.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Temporary differences arising from the differences between the tax basis of an asset or liability on the balance sheet are used to calculate future income tax assets or liabilities. Future income tax assets or liabilities are calculated using the rates that are anticipated to be in effect in the periods that the temporary differences are expected to reverse.

Financial Instruments

Financial instruments consist primarily of accounts receivable, prepaid expenses, accounts payable and accrued liabilities and bank debt. There are no significant differences between the carrying value of these instruments and their estimated fair value.

The Company may use financial instruments for non-trading purposes to manage fluctuations in commodity prices, as described in Note 7. The Company will elect to mark-to-market its financial contracts.



2. Property and Equipment

($ thousands)
As At As at
December 31, December 31,
2006 2005
----------------------------
$ $
----------------------------
Petroleum and natural gas properties and
equipment 114,186 71,909
Furniture, fixtures and other 114 110
----------------------------
114,300 72,019
Less: Accumulated depletion and depreciation 18,794 5,936
----------------------------
95,506 66,083
----------------------------


At December 31, 2006 costs of $ 4,044,889($ 1,440,000 at December 31, 2005) with respect to unproved properties have been excluded from costs subject to depletion. Direct salary costs related to geological and geophysical personnel in the amount of $ 172,000 ($361,000 in 2005) have been charged to petroleum and gas properties during the year. No other salary or overhead charges have been capitalized.

3. Bank Indebtedness

At December 31, 2006 the Company's credit facility comprises a revolving Operating Demand Loan facility with a credit limit of $50,000,000 that bears interest at bank prime plus one eighth percent.

This facility has no specific terms of repayment aside from the bank's right of demand and periodic review and is secured by a general assignment of book debts, a $50,000,000 debenture with a first floating charge over all assets with a negative pledge and an undertaking to provide fixed charges on the Company's major producing reserves at the request of the bank.

4. Share Capital

Authorized:

An unlimited number of common voting shares and an unlimited number of preferred shares issuable in series for which the directors may fix, among other things, the rights, privileges, restrictions, conditions, voting rights, rates, method of calculation and dates of payment of dividends and terms of redemption, purchase and conversion if any, and any other provisions.



Issued and outstanding:

Common Voting Shares Number of Amounts
Shares $
----------------------------------------------------------------------------
Issued upon transfer from Olympia
Energy Inc. 4,263,936 4,263,936
Issued for oil and gas properties 469,000 469,000
Issued on private placement - flow
through shares 2,553,500 2,553,500
Issued on private placement 2,446,500 2,446,500
Issued on private placement 3,500,000 7,175,000
Share issuance costs (net of tax) (313,431)
----------------------------------------------------------------------------
Balance, December 31, 2004 13,232,936 16,594,505
Tax effect of flow through shares (858,487)
Issued on private placement 2,000,000 14,500,000
Share issuance costs (net of tax) (618,492)
----------------------------------------------------------------------------
Balance, December 31, 2005 15,232,936 29,617,526
----------------------------------------------------------------------------
Exercise of Stock Options 16,666 74,164
Issued on private placement - flow
through shares 1,248,300 10,485,720
Share issuance costs, net of tax (459,787)
----------------------------------------------------------------------------
Balance, December 31, 2006 16,497,902 39,717,623
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The tax benefits related to the $2,553,500 of flow through shares issued in 2004 were renounced to flow through shareholders and booked to the accounts in February 2005. Similarly, the corporation is committed to spend $10,486,000 on CEE expenditures to fulfil its flow-through obligation issued in 2006. Qualifying expenditures will primarily be made and renounced in the first quarter of 2007.

The following table reconciles the common shares used in calculating net earnings per common share:



December 31,
2006 2005
--------------------------
Weighted average common voting shares
outstanding - basic 15,325,924 14,328,826
Effect of dilutive stock options 1,121,132 1,144,074
--------------------------
Weighted average common shares
outstanding - diluted 16,447,056 15,472,900
--------------------------


Stock Options

Under the terms of the Accrete Energy Inc. 2004 Incentive Stock Option Plan, as amended, (the "plan"), directors, officers, employees and consultants (the "Participant(s)") are eligible to be granted options to purchase common shares. The plan provides for granting up to 1,926,394 common shares.

The maximum number of option shares that may be reserved for issuance to any one Participant under the plan cannot exceed 5% of the issued and outstanding common shares.

The exercise price under the plan is defined by the plan to be the closing price on the principal stock exchange on which the common shares are traded on the last business date preceding the date of grant or if the common shares did not trade on that date, the weighted average price for the five trading days preceding the date of grant.

The vesting of stock options is determined by the board of directors and the term, as also determined by the board of directors cannot exceed five years from the date of grant of such options.

A Participant's entitlement under the plan ceases upon ceasing to be a Participant. If such cessation is involuntary, then the vested and unvested options can be exercised for a period of ninety days after such date. Where a Participant is terminated for cause, the Participant may only exercise those options that have become vested. Where a Participant is terminated by the company without cause, the Participant is entitled to exercise stock options that have vested during the notice period or in the event of compensation being paid in lieu of notice, for 21 days after ceasing to be a Participant.

Options granted under the plan are not assignable and no financial assistance is extended to optionees.

The board of directors is empowered to amend the plan. Any amendment to the plan is subject to the receipt of necessary regulatory approvals and any amendment required by applicable law or regulatory policy to be approved by shareholders does not become effective until so approved.

The following table summarizes information about stock options outstanding at December 31, 2006:



Weighted Number Weighted
Average Exercisable Average
Remaining (Vested) Exercise
Options Contractual Price
Grant Price Outstanding Life ($/Share)
----------------------------------------------------------------------------
$ 1.00 926,845 2.4 Years 926,845 1.00
$ 2.30 40,000 2.8 Years 26,667 2.30
$ 2.60 395,000 2.9 Years 263,333 2.60
$ 2.89 5,000 2.9 Years 3,333 2.89
$ 3.12 40,000 2.9 Years 26,667 3.12
$ 7.01 9,000 3.4 Years 3,000 7.01
$ 6.91 10,000 4.8 Years 0 6.91
----------------------------------------------------------------------------
1,425,845 2.6 Years 1,249,845 1.63
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Options Outstanding:

Balance, December 31, 2005 1,465,845
Issued during 2006 10,000
Exercised and Forfeited (50,000)
----------
Ending Balance, December 31, 2006 1,425,845
----------
----------


The options granted have a term of five years to expiry. All but the $1.00 stock options vest equally over a three year period commencing on the first anniversary of the date of grant. The $1.00 stock options vest equally over a three year term commencing with the date of grant.

During the year ended December 31, 2006, 10,000 options were granted with an exercise price of $6.91/share. An estimated fair value of $3.46/share was calculated for these options as at the date of grant using the Black-Scholes model.

The Company has accounted for its employee stock options granted using the fair value method. The fair value of all options granted to December 31, 2006 was estimated to be $3,687,293($2.59 per option granted) This value is charged to stock based compensation cost over the vesting period. A total of $158,483 (2005, $395,597) was charged in the fourth quarter and $821,427 (2005, $2,236,344 ) for the year ended December 31, 2006.

The assumptions used in calculating the fair value include a volatility factor ranging from 45% to 52%, a weighted average risk free interest rate of 3.7% to 4.5%, and a weighted average expected life of the options of 4 to 5 years.

Subsequent to year end, 50,000 options were granted with an exercise price of $5.26/share. These options vest over a three year period commencing January 17, 2008 and expire on January 15, 2012. An estimated fair value of $1.85/share was calculated for these options as at the date of grant using the Black-Scholes model.



Contributed Surplus

($ thousands)

Year Ended December 31,
2006 2005

Balance, beginning of year 2,593 357
Stock Based Compensation 821 2,236
-----------------------
Balance, end of year 3,414 2,593
-----------------------
-----------------------


5. Asset Retirement Obligation

Asset retirement obligation comprises:

($ thousands)

Year Ended December 31,
2006 2005
-----------------------
Balance, beginning of year 1,152 485
Liabilities incurred 494 595
Liabilities settled (44) -
Dispositions (47) -
Accretion expense 108 72
-----------------------
Balance, end of year 1,663 1,152
-----------------------
-----------------------


The total future asset retirement obligation was estimated based on the Company's net ownership interest in all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of the estimated cash flows to settle the asset retirement obligation is approximately $3,207,945 (2005 $3,089,071) which will be incurred over the next twenty five years. A credit adjusted risk-free rate of 7% was used to calculate the fair value of the obligations.

6. Income Taxes

At December 31, 2006, the Company's exploration and development expenditures and undepreciated capital costs total $76,303,000. These costs may be carried forward indefinitely to reduce future taxable income.

The following reconciles the difference between income tax recorded and the expected income tax expense obtained by applying the expected income tax rate to earnings before taxes:



($ thousands)
Year Ended December 31,
2006 2005
$ $
-----------------------
Income/(Loss) before income taxes 5,863 5,839
Statutory Rate 34.12% 37.62%
Expected income tax recovery at the
combined federal and provincial
statutory rate 2,001 2,197
Crown royalties 927 1,406
Resource allowance (895) (1,070)
Alberta Royalty Tax Credits (60) (122)
Stock based compensation cost 280 841
True Up Prior Year Provision 136
Attributed crown royalty income (71) (123)
Tax-rate adjustments (435) (313)
Other 7 9
Valuation allowance - reversed - (272)
-----------------------
Future income tax expense 1,890 2,553
-----------------------
-----------------------


The following table summarizes the tax effect of temporary differences:


($ thousands)
December 31,
2006 2005
$ $
-----------------------
Future income tax assets (liabilities):
Carrying value of capital assets in excess of
tax basis (5,836) (3,976)
Asset retirement obligation 483 387
Share issue costs 405 370
Attributed crown royalty income 175 128
-----------------------
4,773 3,091
-----------------------
-----------------------


7. Financial Instruments

The Company's financial instruments recognized on the balance sheets consist of accounts receivable, bank indebtedness, and accounts payable and accrued expenses. The fair value of all financial instruments classified as current assets or current liabilities approximate their carrying amounts due to the short-term maturity of these instruments.

A portion of the Company's accounts receivable are from joint venture partners in the oil and gas business and are subject to normal industry credit risk. Purchasers of the Company's petroleum and natural gas products are subject to an internal credit review designed to mitigate the risk of non-payment and the carrying value reflects management's assessment of the associated credit risks.

The Company is exposed to fluctuations in commodity prices that are based in foreign currency.

The Company did not enter into any contracts during the year that would have reduced its exposure to fluctuations in commodity prices or exchange rates.

Subsequent to year-end, the Company entered into the following contracts:



Type Amount Term Price ($/GJ) Type
----------------------------------------------------------------------------
Collar 2,000GJ/d February 1-October 31, 2007 $5.50-$8.25 at AECO Financial
Collar 2,000 GJ/d March 1-October 31, 2007 $5.50-9.13 at AECO Financial


8. Supplemental Cash Flow Information

Change in non-cash working capital comprises:


($ thousands) December 31,
2006 2005
$ $
-----------------------
Accounts receivable 800 (5,041)
Prepaid expenses (67) 8
Accounts payable and accrued liabilities (10,174) 12,116
-----------------------
Change in non-cash working capital (9,441) 7,083
-----------------------
Relating to:
Investing activities (7,317) 7,948
Operating activities (2,124) (865)
-----------------------
(9,441) 7,083
-----------------------
-----------------------


9. Commitments

The Company has entered into various commitments related to the leasing of
office premises and office equipment. The payments due under such leases are
as follows:


Contractual
obligations 2007 2008 2009 2010 2011 Thereafter
($ thousands) $ $ $ $ $ $
----------------------------------------------------------------------------
Office Premises 189 47 - - - -
Office equipment 9 2 1 - - -
-----------------------------------------
198 49 1 - - -
-----------------------------------------
-----------------------------------------



Contact Information

  • Accrete Energy Inc.
    Mr. Peter Salamon
    President and CEO
    (403) 269-8846
    or
    Accrete Energy Inc.
    Mr. Tom Dalton
    Vice President Finance
    (403) 269-8846
    or
    Accrete Energy Inc.
    2100, 500 - 4th Avenue SW
    Calgary, Alberta T2P 2V6
    Email: investor@accrete-energy.com
    Website: www.accrete-energy.com