E4 Energy Inc.
TSX VENTURE : EFE

E4 Energy Inc.

April 16, 2007 07:00 ET

E4 Announces 2006 Financial Results and Reserves Information

CALGARY, ALBERTA--(CCNMatthews - April 16, 2007) - E4 Energy Inc. ("E4" or the "Company") (TSX VENTURE:EFE) is pleased to announce today its fourth quarter and year-end December 31, 2006 audited financial results and 2006 reserves information. A summary of E4's results are detailed as follows:

2006 Corporate Highlights

Reserves.

- At December 31, 2006 proved plus probable reserves increased to 3.2 million barrels of oil equivalent (boe) from 2.1 million boe at December 31, 2005, an increase of 52 percent.

- Total proved reserves increased to 1.8 mm boe at December 31, 2006 compared to 1.2 mm boe at December 31, 2005, an increase of 51 percent.

- All reserve adds from the 2006 year can be attributed to in-house play generation and drill-bit success.

Capital Efficiencies

- Demonstrated cost effective reserve growth for 2006, through drilling and minor acquisitions, after revisions:



-- proved plus probable FD&A including future development capital $20.83/boe
-- proved plus probable FD&A excluding future development capital $16.94/boe
-- proved FD&A including future development capital $30.95/boe
-- proved FD&A excluding future development capital $26.10/boe


Year-End Net Asset Value (NAV)

- Estimated per fully diluted share:

-- at 5% BT (forecast pricing) $1.45/share (24% increase from 2005 year-end)

-- at 10% BT (forecast pricing) $1.20/share (21% increase from 2005 year-end)

Financial Accomplishments

- Capital expenditure increased to $23.5 million from $10.9 million in 2005, including $5.3 million in land and seismic to provide for future growth opportunities.

- Bank debt and working capital deficit at December 31, 2006 was $9.6 million, significantly below the $18 million demand revolving operating credit facility available.

- Petroleum and natural gas revenue was $15.5 million for 2006 compared to $16.2 million during the prior year, primarily attributed to lower commodity prices received in 2006.

- Per unit operating costs and transportation expenses decreased from $12.59 per boe in 2005 to $10.76 per boe in 2006, a decrease of 17%.

- General and administrative expenses decreased from $4.87 per boe in 2005 (excluding severances) to $3.96 per boe in 2006.

- Successfully closed a $7.0 million bought deal flow through financing on November 30, 2006.

Production.

- Daily production for 2006 averaged 860 boe/d compared to an average of 730 boe/d for 2005, an 18 percent year over year increase.

- Average daily production for the fourth quarter of 2006 was 1,052 boe/d compared to 905 boe/d for the third quarter of 2006, a quarter over quarter increase of 16 percent.

Land Growth.

- On December 31, 2006 the Company held 75,614 net undeveloped acres of land compared to 48,857 net undeveloped acres as at December 31, 2005, an increase of 55 percent.

Operational Review.

- During the fourth quarter of 2006, E4 drilled a total of 8 (6.1 net) wells which resulted in 4 (3.1 net) potential oil wells, 3 (2 net) potential gas wells and 1 (1 net) D&A well for an overall success ratio of 88 percent.

Operational Review and First Quarter Update

E4 has had a successful and active 2006. The Company drilled 27 (20.4 net) wells resulting in 12 (7.8 net) oil wells, 10 (8.0 net) gas wells, 3 (2.6 net) suspended wells and 2 (2 net) D&A wells. Operations were concentrated on lower risk oil development in Metiskow, Alberta and on higher reward/risk projects in Ft. St. John, in N.E. B.C., as well as a new potential shallow gas project in the Fincastle area of Southern Alberta.

In the Company's most active drilling area of Metiskow, Alberta, E4 drilled 11 (6.6 net) wells, all of which were part of the Company's lower risk, step-out development program. This resulted in 8 (4.6 net) oil wells and 3 (2.1 net) D&A or standing wells for a present day production rate of 120 gross bbls/d. In the first quarter 2007, E4 recently drilled 1 oil well (0.92 net) in the area which has recently been put on production at 40 bbls/d.

At the beginning of the third quarter of 2006, E4 drilled its first horizontal well into the previously announced new pool discovery (60 percent working interest) on the Company's Provost East property. The Company then followed up with a second horizontal well in the fourth quarter. Both wells are presently producing at a restricted combined rate of 75 bbls/d. Additionally, E4 purchased the 100 percent working interest in an adjacent abandoned oil pool. Both oil pools have potential in place oil of more than 3 million barrels each. Each pool has an additional 3 - 5 horizontal drilling locations. Typical for the play type, the area presently requires a water handling facility before further drilling and production is pursued. E4 plans to have this facility operational by the end of the second quarter.

At Airport, near Ft. St. John in British Columbia, In 2006, E4 drilled 1 (1.0 net) successful gas well and 1 (1.0 net) suspended gas well. The first well has been producing for 8 months from the Halfway zone at an average rate of 250 boe/d. The well also exhibited several other potential zones of which have still yet to be tested. From continued technical work using 3-D seismic, E4 sees the potential for further follow up locations in both the Halfway formation and potential bypass pay zones. The Company has chosen to drill these wells in the second quarter, so E4 can take advantage of B.C. Government drilling related royalty incentives and an anticipated decrease in operational expenses.

In the area of Boundary Lake, British Columbia, E4 drilled a new oil pool discovery well in the fourth quarter, 2006. The well was recently put on production at a rate of 75 bbls/d. A follow up location was then drilled in the first quarter of 2007 to test the northern limits of the oil pool but did not encounter commercial quantities of hydrocarbons. The Company still has an additional 3 drillable development locations within the new discovery pool, of which 1 - 2 locations are planned for later this year.

In the Fincastle area of Southern Alberta, E4 drilled 7 (6.0 net) wells over the course of the year. In conjunction with this drilling program, the Company has pursued and accumulated over 42,000 net undeveloped acres of land. In the first quarter of 2007, E4 has drilled 2 (1.0 net) additional wells. At this point, 4 (3.0 net) of the 9 (7.0 net) wells have been tied-in. The prospective producible zones in this area are the Second White Specks, Medicine Hat and the Barons, formations. Much of the exploration project area is still in the early development stages, where the better tested wells and formations have yet to be tied-in. E4 presently produces 20 net boe/d from the area. The Company plans to drill additional wells this year, and proceed with production tie-ins.

In the Chain/Mikwan area of Alberta, E4 had originally planned in 2006 to drill 9 development wells for Horseshoe Canyon formation CBM potential. Based on lower than expected natural gas prices, the Company chose to delay this program and reallocate the funds towards land purchases in Fincastle. In the first quarter of 2007, E4 has now drilled and cased 6 (6.0 net) gas wells of this program. Presently, the Company is awaiting break-up for completing and the tie-in of all of these wells. Expected production adds from the 6 wells is approximately 120 boe/d. E4 plans to drill 3 more CBM wells in Mikwan this year.

Outlook

As the oil and gas industry has gone through a very unsettled period of time, in part fuelled by the unpredictable nature of commodity pricing, junior emerging companies have encountered challenges in executing a sound business strategy. E4 has prepared and is currently executing a business plan allowing for E4 to remain sustainable through the changing business cycles.

Being a full-cycle exploration company with the key attributes necessary to implement its business plan, E4 has continued to grow its extensive inventory of exploration and development prospects. In 2006, more than 20 percent of the Company's budget was dedicated towards land acquisitions, thereby providing the necessary growth potential for 2007 and beyond. For 2007, E4 has plans to drill 8 new exploratory locations that have the potential to lead to significant new pool discoveries. In a success case scenario, these operations could lead to more than 25 additional development locations.

For the year 2007, the Company has an initial capital expenditure budget of $20 million for exploration and development projects. This budget will be financed by funds from operations and bank credit facilities, which combined with the equity offering previously undertaken in November 2006, E4 will be able to pursue its active growth program throughout the year.

MANAGEMENT'S DISCUSSION AND ANALYSIS (MD&A)

The following discussion and analysis as provided by the management of E4 Energy Inc. ("E4" or "the Company") as of April 16, 2007, is to be read in conjunction with the audited financial statements and related notes for the years ended December 31, 2006 and 2005, all of which were prepared in accordance with Canadian generally accepted accounting principles (GAAP). The reporting and the functional currency is the Canadian dollar, except as noted.

Description of Company - E4 Energy Inc., formerly known as Southpoint Resources Ltd., is an independent, emerging crude oil and natural gas company actively engaged in the exploration for, development and production of natural gas and crude oil reserves in Alberta and British Columbia, Canada. The Company is subject to the provisions of the Alberta Business Corporations Act and its common shares are publicly listed and traded on the TSX Venture Exchange under the symbol EFE.

Non-GAAP Measures- The MD&A contains the term "funds generated from operations" and "netbacks", both of which are non-GAAP terms. The Company uses these measures to help evaluate its performance. Management considers netbacks an important measure as it demonstrates its profitability relative to current commodity prices. Management uses funds generated from operations to analyze operating performance and leverage and considers funds generated from operations to be a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and to repay debt. Funds generated from operations should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with GAAP as an indicator of the Company's performance. Therefore references to funds generated from operations or funds generated from operations per share (basic and diluted) may not be comparable with the calculation of similar measures by other entities. All references to funds generated from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital. Funds generated from operations per share are calculated using the basic and diluted weighted average number of shares for the period.

Boe Presentation - Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet (mcf) to one barrel (bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and is not intended to represent a value equivalency at the wellhead. All boe conversions in this report are derived by converting natural gas to oil in the ratio of 6 mcf of natural gas to 1 bbl of oil.

Forward-Looking Information - Statements throughout this MD&A that are not historical facts may be considered "forward-looking statements". These forward-looking statements sometimes include words to the effect that management believes or expects a stated condition or result. Forward-looking statements included in the MD&A concern anticipated production and capital expenditures.

Forward-looking statements and information are based on the Company's current beliefs as well as assumptions made by and information currently available to the Company concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third-party operators; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax laws; and the Company's ability to access external sources of debt and equity capital.

The Company cautions that the foregoing list of factors that may affect future results is not exhaustive. When relying on the Company's forward-looking statements to make decisions with respect to the Company, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. The forward-looking statements and information contained in this MD&A are as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

CREATION OF E4 ENERGY INC.

Naneco Minerals Ltd. was continued under the laws of the Province of Alberta and changed its name to Southpoint Resources Ltd. on February 6, 2002. Southpoint at that time refocused its efforts to the exploration and development of petroleum and natural gas in Western Canada. On August 24, 2005, the Company changed its name to E4 Energy Inc. in conjunction with the business combination discussed in Note 3 to the audited consolidated financial statements for the year ended December 31, 2006.



OPERATIONAL HIGHLIGHTS

The financial data presented below has been presented in accordance with
GAAP. The reporting and the measurement currency is the Canadian dollar.

-------------------------------------------
2006 2005 2004
-------------------------------------------
Year Year Year
Q4 Ended Q4 Ended Q4 Ended
Operational Results
Production
- Natural gas (mcf/d) 4,086 3,346 2,848 2,465 1,694 1,420
- Crude oil and NGLs (bbls/d) 371 302 248 319 376 246
- Total production (boe/d) 1,052 860 723 730 658 483

Average realized pricing
- Natural gas ($/mcf) 7.38 6.89 12.28 9.57 7.09 6.64
- Crude oil ($/bbl) 55.36 64.15 67.63 64.77 55.76 51.00
- Combined average ($/boe) 48.20 49.33 71.61 60.56 50.26 45.57

Selected Financial Results
($ thousands)
Petroleum and natural gas
revenue 4,665 15,486 4,768 16,202 3,049 8,055
Royalties 852 2,869 880 2,750 270 645
Operating expenses and
transportation 1,088 3,379 774 3,356 612 1,804
General and administrative
expenses 505 2,433 775 2,685 436 1,645

Funds generated from operations 2,191 7,502 2,752 7,708 1,484 3,465
- Basic per share 0.05 0.19 0.07 0.28 0.07 0.16
- Diluted per share 0.05 0.19 0.07 0.28 0.07 0.16

Cash flow from operating
activities 2,862 6,847 2,161 5,694 2,707 3,238

Depletion, depreciation and
accretion expense 2,838 9,433 2,254 7,363 1,336 6,038

Net earning (loss) before
discontinued operations (347) (119) 409 304 832 (1,820)
- Basic per share (0.01) (0.00) 0.01 0.01 0.04 (0.08)
- Diluted per share (0.01) (0.00) 0.01 0.01 0.04 (0.08)

Net earnings (loss) (347) (119) 409 304 818 (1,956)
- Basic per share (0.01) (0.00) 0.01 0.01 0.04 (0.09)
- Diluted per share (0.01) (0.00) 0.01 0.01 0.04 (0.09)

Capital spending 4,482 23,543 4,458 10,912 4,837 11,365

Total assets 68,305 68,305 52,741 52,741 36,041 36,041

Total debt and working capital
deficiency 9,649 9,649 796 796 12,281 12,281

Shareholders' Equity 47,103 47,103 40,446 40,446 15,396 15,396

Common shares outstanding
(thousands) 42,644 42,644 38,671 38,671 22,577 22,577


SELECTED QUARTERLY INFORMATION

The financial data presented below has been presented in accordance with
GAAP. The reporting and the measurement currency is the Canadian dollar.

-----------------------------------------------------------
2006 2005
-----------------------------------------------------------
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
Operational
Results
Production
Natural gas
(mcf/d) 4,086 3,352 2,766 3,171 2,848 2,248 2,280 2,481
Crude oil and
NGL(1)(bbls/d) 371 346 214 275 248 249 296 486
Total
production
(boe/d) 1,052 905 675 804 723 624 676 900

Average
realized
pricing
Natural gas
($/mcf) 7.38 6.10 6.15 7.74 12.28 9.79 7.47 8.18
Crude oil
($/bbl) 55.36 70.30 68.94 64.74 67.63 71.78 63.01 60.72
Combined
average
($/boe) 48.20 49.45 47.08 52.68 71.61 63.95 53.18 55.46

Selected
Financial
Results ($000s
except
per share)

Petroleum and
natural gas
revenue 4,665 4,117 2,892 3,812 4,768 3,670 3,271 4,493

Royalties 852 656 521 840 880 592 550 728
Operating
expenses and
transportation 1,088 858 667 766 774 676 890 1,016

General and
administrative
expenses 505 462 714 752 775 968 523 419

Funds generated
from operations 2,191 2,221 1,252 1,838 2,752 1,500 1,144 2,312

Cash flow from
operating
activities 2,862 479 834 2,672 2,161 2,598 (1,633) 2,568

Depletion,
depreciation
and accretion
expense 2,838 2,433 1,875 2,287 2,254 1,563 1,506 2,040

Net earnings
(loss) (347) 173 826 (771) 409 (310) (422) 627
- Basic per
share (0.01) 0.00 0.02 (0.02) 0.01 (0.01) (0.02) 0.03
- Diluted per
share (0.01) 0.00 0.02 (0.02) 0.01 (0.01) (0.02) 0.03

Capital
spending 4,482 3,617 7,848 7,596 4,458 2,310 871 3,273

Total debt and
working capital
deficiency 9,649 13,952 12,694 6,337 796 9,289 12,992 13,365

Shareholders'
Equity 47,103 40,543 40,006 38,557 40,446 29,067 15,304 15,653

Common shares
Outstanding
(thousands) 42,644 38,755 38,755 38,755 38,671 33,624 22,577 22,577

(1) natural gas liquids


Petroleum and Natural Gas Production

E4's production for the year ended December 31, 2006 averaged 860 boe per day. The production was comprised of 302 bbls per day of crude oil and natural gas liquids (NGL) and 3,346 mcf per day of natural gas. This compares with yearly production for the year ended December 31, 2005 of 730 boe per day, split between crude oil and NGL of 319 bbls per day and natural gas of 2,465 mcf per day. The 18 percent increase in total production was due in large part to a successful drilling program in the Airport area of British Columbia.

In Q4 2006, production averaged 1,052 boe per day, an increase of 46 percent from Q4 2005 when production averaged 723 boe per day. Q4 2006 crude oil and NGL production was 371 bbls per day, compared to Q4 2005 production of 248 bbls per day. Natural gas production, meanwhile, was 4,086 mcf per day in Q4 2006 and 2,848 mcf per day in the same period of 2005. These production increases were due to new production from the Airport area of British Columbia and the Provost area of Alberta.



The following table highlights E4's production by reporting period:

Average Daily Production
-------------------------------------------------
Natural Gas Crude Oil and NGL Total
(mcf/d) (bbls/d) (boe/d)(6:1)
------------- ------------------- -------------

Q1 2006 3,171 275 804
Q2 2006 2,766 214 675
Q3 2006 3,352 346 905
Q4 2006 4,086 371 1,052

Year 2006 3,346 302 860

Q1 2005 2,481 486 900
Q2 2005 2,280 296 676
Q3 2005 2,248 249 624
Q4 2005 2,848 248 723

Year 2005 2,465 319 730


Revenue and Commodity Pricing

E4's petroleum and natural gas revenue for 2006 (before royalties) totalled $15.5 million, comprised of natural gas sales of $8.4 million and crude oil and NGL revenue of $7.1 million. This compares with total revenues of $16.2 million for 2005, which consisted of $8.7 million of natural gas sales and $7.5 million of crude oil and NGL sales. The 4 percent decrease from 2005 to 2006 is due to substantially lower natural gas prices throughout 2006, largely offset by E4's production increases.

During Q4 2006, E4 recorded total revenue before royalties of $4.7 million, consisting of $1.9 million of crude oil and NGL sales and $2.8 million of natural gas sales. This represents a 2 percent decrease from the Q4 2005 total revenue of $4.8 million, which consisted of $3.2 million of natural gas sales and $1.6 million of crude oil and NGL sales. Although E4's average daily production was higher in Q4 2006 as compared to Q4 2005, this increase was offset by lower commodity prices in Q4 2006, resulting in revenues that were virtually unchanged for the respective periods.

There were no outstanding derivative instruments to hedge future commodity prices during the years ended December 31, 2006 and December 31, 2005. However, the Company has put into place a fixed price natural gas sales contract for 1,500 gigajoules per day commencing in April 2007.

The following table highlights the composition of E4's revenue before royalties by reporting period:



($000s) Natural Gas Crude Oil and NGL Total
------------- ------------------- -------------

Q1 2006 2,210 1,602 3,812
Q2 2006 1,549 1,343 2,892
Q3 2006 1,880 2,237 4,117
Q4 2006 2,776 1,889 4,665
------------- ------------------- -------------

Year 2006 8,415 7,071 15,486

Q4 2005 3,223 1,545 4,768
Year 2005 8,658 7,544 16,202
Year 2004 3,451 4,604 8,055

The following table highlights E4's corporate realized wellhead prices and
industry benchmark prices:

2006 Quarterly Comparison Year Year
Q4 Q3 Q2 Q1 2006 2005
------- ------- -------- ------- ------- --------
E4 prices:
Natural gas ($/mcf) 7.38 6.10 6.15 7.74 6.89 9.57
Crude oil and NGL ($/bbl) 55.36 70.30 68.94 64.74 64.15 64.77
Combined ($/boe) 48.20 49.45 47.08 52.68 49.33 60.56

WTI oil at Cushing,
Oklahoma (US$/bbl) 60.21 70.55 70.70 63.48 66.24 56.62
Edmonton Par light oil
($/bbl) 64.48 79.17 78.60 69.11 72.84 68.22
Bow River medium oil
($/bbl) 45.69 59.06 62.16 51.29 54.55 44.40
WTI - Lloyd blend
differential (US$/bbl) 21.31 19.08 17.16 10.26 16.95 21.41

Nymex Henry Hub natural gas
(US$/mmbtu) 6.61 6.52 6.83 9.10 7.26 8.55
AECO natural gas - monthly
index ($/mcf) 6.31 5.98 6.22 9.23 6.92 8.42
Currency Exchange rate
(US$:Cdn$) 0.878 0.892 0.891 0.866 0.882 0.824


Petroleum and Natural Gas Royalties

The Company incurred an effective royalty rate of 18.5 percent in 2006. This royalty rate, net of the Alberta Royalty Tax Credit (ARTC), compares with a rate of 17 percent for 2005. This slight increase is due to adjustments pertaining to prior periods that were first recognized in the first quarter of 2006. In total dollars, E4 incurred royalties of $2.9 million in 2006 and $2.8 million in 2005.

E4's petroleum and natural gas royalties for Q4 2006 amounted to $0.9 million, identical to the same period of 2005. As a percentage of gross revenue, E4's corporate royalty rate was 18.2 percent for the fourth quarter of 2006 and 18.5 percent for the same period of 2005. On a go-forward basis, E4 expects a slightly higher royalty rate due to the Alberta government's elimination of the ARTC effective January 1, 2007.



The following table highlights E4's effective royalty rates:

($000s except per unit 2006 Quarterly Comparison Year Year
and royalty rate) Q4 Q3 Q2 Q1 2006 2005
------- ------- -------- ------- ------- --------
Crown, net of ARTC 763 588 444 670 2,465 2,282
Freehold and overriding 89 68 77 170 404 468
Total 852 656 521 840 2,869 2,750
------- ------- -------- ------- ------- --------
------- ------- -------- ------- ------- --------

Per unit ($/boe) 8.81 7.87 8.48 11.61 9.14 10.32
Effective royalty rate (%) 18.2% 15.9% 18.0% 22.0% 18.5% 17.0%


Operating Expenses

E4 reported field operating costs of $9.21 per boe for the year ended December 31, 2006. This was slightly lower than the average operating costs of $9.49 per boe for the year ended December 31, 2005 and was a result of management's implementation of programs to reduce operating costs such as negotiating more favourable contract operating fees. In total dollars, E4 reported field operating costs of $2.9 million for the year ended December 31, 2006 compared to $2.5 million for the prior year.

In Q4 2006, E4 reported field operating costs of $9.85 per boe. This was 2 percent higher than in the same period of 2005, and the increase is attributable to several compressor repairs that occurred in Q4 2006. In total dollars, E4 incurred field operating costs of $1.0 million in Q4 2006 compared to $0.6 million for the same period of 2005. This increase of 49 percent is due to higher overall production in Q4 2006.



2006 Quarterly Comparison Year Year
Q4 Q3 Q2 Q1 2006 2005
------- ------- -------- ------- ------- --------
Total ($000s) 953 742 563 633 2,891 2,528

Per unit of production
($/boe) 9.85 8.92 9.16 8.76 9.21 9.49


Transportation Expenses

E4 reported transportation costs of $1.55 per boe for the year ended December 31, 2006, compared to $3.10 per boe for the year ended December 31, 2005. The sharp decrease is due to the lower rates being offered by the trucking contractor utilized in 2006 compared to the trucking contractor utilized in 2005. In Q4 2006, E4 reported transportation costs of $1.40 per boe compared to $2.00 per boe for the same period of 2005.



2006 Quarterly Comparison Year Year
Q4 Q3 Q2 Q1 2006 2005
------- ------- -------- ------- ------- --------
Total ($000s) 135 116 104 133 488 828

Per unit of production
($/boe) 1.40 1.39 1.69 1.83 1.55 3.10


General & Administrative Expenses (G&A)

For the year ended December 31, 2006, total G&A expenses decreased by 9 percent from the same period of 2005. In 2006, E4 reported total G&A expenses of $2.4 million compared to $2.7 million in 2005. The decrease was due in large part to the absence of severance costs in 2006, versus costs of $0.6 million in 2005. On a per unit of production basis, G&A expenses were $7.75 per boe in 2006 compared to $7.93 per boe in 2005, excluding severance costs related to the P3 business combination.

E4's total G&A expenses for Q4 2006 amounted to $0.5 million or $5.20 per boe of production, compared to $0.8 million or $11.65 per boe for the comparable 2005 period. This sharp decrease is mostly attributable to non-cash stock-based compensation expense. In Q4 2006, E4 recorded stock-based compensation expense net of capitalization of $0.2 million, or $1.64 per boe. This compares to $0.5 million or $6.77 per boe in Q4 2005.

The Company capitalized employee and associated direct overhead costs of its technical personnel in the amount of $0.9 million in fiscal 2006 and $0.2 million in Q4 2006. In comparison, E4 capitalized overhead in the amount of $0.4 million in fiscal 2005 and $0.2 million in Q4 2005. E4 currently employs 11 office personnel, including six technical staff and engages the services of two consultants on a part-time basis.



2006 Quarterly Comparison Year Year
($000s) Q4 Q3 Q2 Q1 2006 2005
------- ------- -------- ------- ------- --------
Cash costs 542 426 605 526 2,099 2,287
Capitalized cash costs (197) (192) (274) (193) (856) (417)
Stock-based compensation
(net of capitalization) 160 228 383 419 1,190 815
------- ------- -------- ------- ------- --------
Total 505 462 714 752 2,433 2,685
------- ------- -------- ------- ------- --------
------- ------- -------- ------- ------- --------

Per unit ($/boe)
Cash costs 5.60 5.12 9.84 7.26 6.69 6.43
Severances - - - - - 2.15
Capitalized cash costs (2.04) (2.31) (4.46) (2.66) (2.73) (1.56)
Stock-based compensation
(net of capitalization) 1.64 2.74 6.24 5.80 3.79 3.06
------- ------- -------- ------- ------- --------
Total per unit 5.20 5.55 11.62 10.40 7.75 10.08
------- ------- -------- ------- ------- --------
------- ------- -------- ------- ------- --------


Financing Charges

In fiscal 2006 the Company recorded total financing charges of $0.5 million, which consisted of interest expense related to the Company's bank facility of $0.42 million and Part XII.6 tax of $0.04 million. For fiscal 2005, the Company recorded $0.7 million in financing charges, consisting of $0.4 million relating to bank borrowing interest charges on its outstanding debt during the period, $0.1 million in accretion relating to subordinated notes and $0.2 million relating to the early retirement of subordinated notes.

In Q4 2006, the Company recorded total financing charges of $0.2 million, relating entirely to interest on the Company's outstanding debt during the period. In Q4 2005, the Company recorded total financing charges of $0.04 million, also relating entirely to interest on the Company's outstanding debt during the period.



2006 Quarterly Comparison Year Year
($000s) Q4 Q3 Q2 Q1 2006 2005
------- ------- -------- ------- ------- --------
Interest expense, including
Part XII.6 tax 189 148 88 35 460 420
Subordinated note accretion - - - - - 117
Loss on early retirement of
subordinated note - - - - - 147
Total 189 148 88 35 460 684
------- ------- -------- ------- ------- --------
------- ------- -------- ------- ------- --------


Depletion, Depreciation and Accretion

E4's depletion and depreciation expenses for the year and quarter ended December 31, 2006 amounted to $9.3 million and $2.8 million, respectively. This equated to $29.70 per boe and $29.00 per boe for the respective periods. For the year and quarter ended December 31, 2005, the Company recorded depletion and depreciation expense of $7.3 million and $2.2 million, respectively, or $27.35 per boe and $33.51 per boe, respectively. The entire oil and gas industry has been hit by higher service costs and the high depletion rates are a result of these higher costs.

The Company's accretion expense relating to its asset retirement obligations (ARO) amounted to $0.1 million for the years ended December 31, 2006 and 2005. In Q4 2006 and Q4 2005, the Company reported accretion expense of $0.03 million in each period.



2006 Quarterly Comparison Year Year
($000s) Q4 Q3 Q2 Q1 2006 2005
------- ------- -------- ------- ------- --------
Depletion & depreciation 2,807 2,405 1,844 2,264 9,320 7,291
Accretion 31 28 31 23 113 72
Total 2,838 2,433 1,875 2,287 9,433 7,363
------- ------- -------- ------- ------- --------
------- ------- -------- ------- ------- --------

Per unit combined ($/boe) 29.33 29.22 30.50 31.61 30.06 27.62


Income and Capital Taxes

The Company currently has approximately $38.8 million in tax pools available for deduction against future taxable income (net of any projected pool usage necessary to offset taxable income for the year ended December 31, 2006). As a result of these tax pools, E4 does not expect to be cash taxable in the foreseeable future.

With respect to E4's future income tax accounting provision for 2006, the Company recorded a future income tax recovery of $3.0 million. The bulk of this recovery includes the impact of a reduction in federal and provincial tax rates in respect of 2006 through 2010 of $0.8 million, a reduction of tax valuation allowance of $1.4 million.



The following table outlines the approximate tax pools available to the
Company at December 31, 2006.

($000s)
-----------
Access Rate Amount
Canadian exploration expense (CEE) 100% $ 5,001
Canadian development expense (CDE) 30% 9,498
Canadian oil and gas property expense (COGPE) 10% 7,696
Undepreciated capital cost (UCC) 25% 11,208
Foreign exploration and development expense (FEDE) 10% 2,094
Non-capital losses 100% 822
Share issue costs 20% 884
Other 20% 1,585
-----------
Total tax pools 38,788
-----------
-----------


Funds Generated From Operations, Cash Flow From Operations and Net Earnings

E4's funds generated from operations totalled $7.5 million for the year ended December 31, 2006. This represents a slight decrease of 3 percent from the $7.7 million in funds generated from operations in 2005. In Q4 2006, the Company's funds generated from operations was $2.2 million, a 27 percent decrease from $2.8 million in Q4 2005. The decreases in the 2006 periods from the respective periods in 2005 are due to lower natural gas prices throughout 2006.

The Company reported a net loss of $0.1 million for the year ended December 31, 2006. This compares with net earnings of $0.3 million for 2005. In Q4 2006, E4 reported a net loss of $0.3 million versus net earnings of $0.4 million in Q4 2005. The net losses reported in the respective periods of 2006 compared to the net earnings reported in the same periods of 2005 were due to lower commodity prices, higher depletion, depreciation and accretion and a recovery in future income taxes.



2006 Quarterly Comparison Year Year
-------------------------------- ------- --------
Q4 Q3 Q2 Q1 2006 2005
------- ------- -------- ------- ------- --------
Funds generated from
operations ($000s) (1) 2,191 2,221 1,252 1,838 7,502 7,708
Per share - basic ($) 0.05 0.06 0.03 0.05 0.19 0.28
Per share - diluted ($) 0.05 0.06 0.03 0.05 0.19 0.28

Cash flow from operating
activities ($000s) 2,862 479 834 2,672 6,847 5,694

Net earnings (loss) ($000s) (347) 173 826 (771) (119) 304
Per share - basic ($) (0.01) 0.00 0.02 (0.02) (0.01) 0.01
Per share - diluted ($) (0.01) 0.00 0.02 (0.02) (0.01) 0.01

(1) Funds generated from operations is a non-GAAP measure and represents
cash flow from operations before changes in non-cash working capital.


Capital Expenditures

E4 incurred capital expenditures of $4.5 million and $23.5 million, respectively, for Q4 2006 and the year ended December 31, 2006. The majority of the capital expenditures incurred was for the drilling of 27 gross wells and land purchases. Outlined below are E4's capital expenditures by category.



2006 Quarterly Comparison Year Year
($000s) Q4 Q3 Q2 Q1 2006 2005
------- ------- -------- ------- ------- --------
Land 469 869 1,003 1,771 4,112 1,463
Seismic 36 - 110 1,012 1,158 706
Drilling & completions 3,228 1,191 6,069 3,538 14,026 5,225
Field facilities &
equipment 452 1,227 151 805 2,635 2,803
Other (1) 205 193 276 193 867 448
------- ------- -------- ------- ------- --------
Total cash capital
expenditures 4,390 3,480 7,609 7,319 22,798 10,645
Non-cash capitalized stock
based compensation 92 137 239 277 745 267
------- ------- -------- ------- ------- --------
Total capital expenditures 4,482 3,617 7,848 7,596 23,543 10,912
------- ------- -------- ------- ------- --------
------- ------- -------- ------- ------- --------

(1) Includes office equipment, computer hardware and direct G&A.


Liquidity and Capital Resources

E4's primary sources of liquidity to fund its exploration and development capital program are the Company's internal funds generated from operations and E4's revolving operating bank credit facility. E4 utilizes this facility to fund daily operating activities and acquisitions as needed. Because of the liquidity and capital resource alternatives available to the Company, including funds generated from operations, E4 believes that its liquidity is sufficient to fund planned spending on exploration and development projects and undeveloped acreage necessary for long-term, profitable growth. The Company anticipates that public capital markets will serve as the principal source of capital to finance any future corporate acquisitions and/or significant property purchases. E4 has issued equity in the past, and expects that this source of capital will continue to be available to the Company in the future to help fund potential acquisitions.

The Company's capital program has been established at $20 million for 2007. Cash provided by operating activities is budgeted to provide a significant portion of the funding for this program. The Company is mindful of the current weakness in Canadian natural gas markets due to seasonal factors and historically high levels of natural gas in storage and re-evaluates its capital program on an on-going basis.

At December 31, 2006, E4 had net debt (bank debt plus/minus working capital) of $9.6 million, 42.6 million common shares outstanding with a carrying amount of $47.5 million and a market capitalization of $52.5 million. In comparison, at December 31, 2005, the Company was capitalized with net debt of $0.8 million, 38.7 million common shares outstanding with a carrying amount of $42.7 million and a market capitalization of $69.6 million. The increase in net debt is attributable to the aggressive capital expenditure program undertaken by E4 in 2006.

As at April 16, 2007, the Company had in-place credit facilities with a major lending institution providing a total borrowing base of $18 million. The bank is expected to conduct its annual credit review in late May 2007.



($000s) 2006 Quarterly Comparison Year Year
-------------------------
End of period Q4 Q3 Q2 Q1 2005 2004
----------------------------------------------------------------------------
Working capital /
deficiency (includes cash) 1,724 69 3,058 1,773 796 5,457
Bank debt, subordinated
notes and convertible
debentures 7,925 13,883 9,636 4,564 - 6,822
------- ------- -------- ------- ------- --------
Total 9,649 13,952 12,694 6,337 796 12,279

Assets 68,305 66,919 64,049 58,126 52,741 36,041


Common Share Information

2006 Quarterly Comparison
------------------------------------------- Year
Q4 Q3 Q2 Q1 2005
---------- ---------- ---------- ---------- ----------
Share High $ 1.51 $ 1.65 $ 1.74 $ 1.85 $ 2.15
price Low $ 1.05 $ 1.14 $ 1.15 $ 1.36 $ 0.91
Close $ 1.23 $ 1.24 $ 1.25 $ 1.42 $ 1.80
Average daily
trading volume 48,629 25,408 53,078 58,895 56,150
Common Outstanding
shares at period
end 42,643,672 38,754,672 38,754,672 38,754,672 38,671,338
Weighted
average
basic 40,107,368 38,754,672 38,754,672 38,752,450 27,557,342
Weighted
average
diluted 40,107,368 38,857,173 38,779,801 38,752,450 27,622,879
Stock Outstanding
options at period
end 3,209,000 3,209,000 3,240,000 3,240,000 2,748,335
Warrants Outstanding
at period
end - - - 667,667 667,667


Contractual Obligations

The Company is committed to contractual obligations and commitments in the
normal course of operations and financing activities. These are outlined
below:

1-3 4-5 Beyond 5
($000s) 1 Year Years Years Years Total
----------------------------------------------------------------------------
Operating lease obligations (1) 189 142 - - 331

(1) Operating lease obligations pertain to the Company's Calgary, Alberta
head office lease. In addition to lease amounts, the Company is
responsible for it proportionate share of operating costs, which are
periodically reviewed and determined by the landlord.


In addition, at December 31, 2006, the Company is committed to incurring approximately $6.4 million prior to December 31, 2007 on qualifying exploration and development expenditures relating to the flow-through financings of November 30, 2006. (See Note 9 (d) to the audited consolidated financial statements at December 31, 2006.)

Risk Management Activities

On January 31, 2007, the Company entered into a firm fixed price agreement with one of its natural gas purchasers. The term of the agreement is such that the first 1,500 gigajoules per day of natural gas production from the Company's McMahon receipt station will have a fixed price of $7.40 per gigajoule. This contract commenced on April 1, 2007 and expires on October 31, 2007.

Off-Balance Sheet Arrangements

The Company did not enter into any off-balance-sheet arrangements during the year ended December 31, 2006.

Related-Party Transactions

A director of the Company is a partner at a law firm that provides legal services to the Company. During the year ended December 31, 2006, the Company paid a total of $0.05 million to this firm for legal fees and disbursements. An additional amount of $0.04 million was accrued at December 31, 2006 and was subsequently paid in 2007.

Newly Adopted Accounting Policies

There were no significant accounting policies newly adopted during the year ended December 31, 2006.

Financial Instruments

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". These 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. These standards create a new statement for comprehensive income that will include changes in the fair value of certain financial instruments. As a result of these new standards, the Company will not use hedge accounting beginning January 1, 2007 and will record the fair value of its crude oil and natural gas derivative contracts under its risk management program. The Company is currently assessing the impact of these new standards on its financial statements.

Business Risks and Uncertainties

The Company's exploration and development activities are focused in the Western Canada Sedimentary Basin within Alberta and British Columbia, which is characterized as being highly competitive with competitors varying in size from small junior producers to significantly larger, fully-integrated energy companies possessing greater financial and personnel resources. The Company recognizes certain risks inherent in the crude oil and natural gas industry, such as finding and developing oil and natural gas reserves at economic costs, drilling risks, producing oil and natural gas in commercial quantities, environmental and safety risks, and commodity price and political risks and uncertainties. E4 has engaged professional management and technical personnel with many years of experience in the oil and natural gas business to address and prudently manage and mitigate these risks.

Disclosure Control Risks

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to its management as appropriate to allow timely decisions regarding required disclosure. The Company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation of the effectiveness of the Company's disclosure controls and procedures as of the date of this MD&A, that disclosure controls and procedures provide reasonable assurance that material information is made known to them by others within the Company. Certain weaknesses, however, have been identified and the Company's Chief Executive Officer and Chief Financial Officer do not expect that the disclosure controls and procedures can prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Internal Controls over Financial Reporting

Multilateral Instrument 52-109 of the Canadian Securities Administrators defines internal controls over financial reporting as "a process designed by, or under the supervision of the issuer's chief executive officers and chief financial officers or persons performing similar functions, and enacted by the issuer's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer's GAAP and includes those policies and procedures that:

a) Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer.

b) Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the issuer's GAAP, and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer.

c) Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer's assets that could have a material effect on the annual financial statements or interim financial statements."

The Company has, under the supervision of its Chief Executive Officer and Chief Financial Officer, designed a process for internal control over financial reporting, which process has been enacted by the Company's board of directors and management. The process was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the Company's GAAP and incorporates policies and procedures as described above.

Given the size of the Company, the evaluation of the design of internal controls over financial reporting for the Company resulted in the identification of the following weaknesses:

1) Management is aware that due to its relatively small scale of operations there is a lack of segregation of duties due to a limited number of employees dealing with accounting and financial matters. However, management has concluded that considering the employees involved and the control procedures in place, including management and Audit Committee oversight, risks associated with such lack of segregation are not significant enough to justify the expense associated with adding employees to clearly segregate duties.

2) As part of its business, the Company records complex and non-routine transactions. These transactions can be very technical in nature and the determination of the appropriate accounting for these transactions requires an in-depth understanding of Canadian GAAP. The Corporation's accounting staff has a fair and reasonable knowledge of the rules related to Canadian GAAP and reporting of the transactions may not be recorded correctly, potentially resulting in a material misstatement of the consolidated financial statement of the Company.

To address this risk, the Company consults with third party expert advisors on a regular basis for advise and seeks specific advice on proposed or contemplated transactions. The Company would have to considerably increase its size and the scope of its activities before the Company could contemplate having dedicated in-house resources with the required knowledge of all aspects of Canadian GAAP that may impact on the complex and non-routine transactions that the Company may enter into.

There have been no significant changes to the Company's internal control over financial reporting that occurred during the most recent period that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Internal Control Reporting

In March 2006 Canadian Securities Administrators decided not to proceed with proposed multilateral instrument 52-111, "Reporting on Internal Control over Financial Reporting" and instead proposed to expand multilateral instrument 52-109, "Certification of Disclosure in Issuers' Annual and Interim Filings". The major changes resulting from this are that the Chief Executive Officer and Chief Financial Officer will be required to certify in the annual certificates that they have evaluated the effectiveness of internal controls over financial reporting (ICOFR) as of the end of the financial year and disclose in the annual MD&A their conclusions about the effectiveness of ICOFR. There will be no requirement to obtain an internal control audit opinion from the issuer's auditors concerning management's assessment of the effectiveness of ICOFR. There is also no requirement to design and evaluate internal controls against an external control framework. This proposed amendment is expected to apply for the year ended December 31, 2008. E4 is continuing with its evaluation of ICOFR to ensure it meets the criteria for the proposed certification for December 31, 2008.

Application of Critical Accounting Policies

The preparation of the Company's audited consolidated financial statements in accordance with Canadian GAAP requires E4's management to make estimates, assumptions and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. The basis for these estimates is historical experience and various other assumptions that the Company believes to be reasonable. Actual results could differ from these estimates under different assumptions and conditions.

For further details on the Company's accounting policies, refer to Note 2 to the to the audited consolidated financial statements for the year ended December 31, 2006.

Full-Cost Accounting

The Company follows the full cost method of accounting for its crude oil and natural gas operations, whereby all costs related to the exploration for and development of oil and natural gas reserves are capitalized and depleted and depreciated using the unit-of-production method based upon the gross proved petroleum and natural gas reserves as determined by an independent qualified reserve engineering firm. In determining costs subject to depletion, the Company includes estimated future costs to be incurred in developing proved reserves and excludes salvage values and the costs of unproved properties. The costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties or until impairment occurs.

In applying the full cost accounting method, a ceiling test is performed to ensure that the capitalized costs are recoverable in the future. Oil and natural gas assets are evaluated in each reporting period to determine whether the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre. The carrying amounts are assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects of the cost centre. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate. The calculation of undiscounted cash flows in the ceiling test can be significantly impacted by fluctuations in any of these estimates.

Asset Retirement Obligation

The asset retirement obligation is estimated based on existing laws, contracts or other policies. The fair value of the asset retirement obligation requires an estimate of the future costs to abandon and reclaim wells, pipelines and facilities discounted to its present value using the Company's credit adjusted risk-free interest rate. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings. Revisions to the estimated timing of cash flows or to the original undiscounted cost could also result in an increase or decrease to the obligation. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.

Income Tax Accounting

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, any income tax liability or asset, as well as any income tax recovery or reduction, may differ from that estimated and recorded by the Company's Management.

For further information, please refer to www.sedar.com.

This press release contains forward-looking statements concerning the Company's expectations of future production, cash flow, earnings and expansion of its oil and gas property interests and concerning the Company's exploration and development drilling, seismic operations, regulatory applications, payout estimates, capital expenditures, number and drilling locations for 2007, seismic acquisitions and facility upgrades. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause actual results to differ from those anticipated. These risks include, but are not limited to: the risks associated with the oil and gas industry (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), acquisitions, commodity price, price and exchange rate fluctuation and uncertainties resulting from competition from other producers and ability to access sufficient capital from internal and external sources. Additional information on these and other risk factors that could affect the Company's operations and/or financial results are included in the Company's reports on file with Canadian securities regulatory authorities.

The forward-looking statements or information contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Oil and Gas Advisory

This press release contains disclosure expressed as "Boe/d". Boe means barrel of oil equivalent and Boe/d means Boe per day. All oil and natural gas equivalency volumes have been derived using the ratio of 6,000 cubic feet of natural gas to 1 barrel of oil. Boe equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of 6,000 cubic feet of natural gas to 1 barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.

In this press release: (i) mmboe means million boe; (ii) boe/d means boe per day; (iii) bbls/d means barrels per day; (iv) mcf means thousand cubic feet; (v) mmcf means million cubic feet; (vi) mcf/d means thousand cubic feet per day; and (vii) mmcf/d means million cubic feet per day.



----------------------------------------------------------------------------
E4 Energy Inc.
Consolidated Balance Sheets
As at December 31 (in thousands of Canadian dollars)
----------------------------------------------------------------------------


2006 2005
----------------------------------------------------------------------------
ASSETS

Current
Cash $ 42 $ 809
Accounts receivable 4,863 3,617
Prepaid expenses and deposits 251 207
-----------------------
5,156 4,633

Property, plant and equipment (Note 4) 54,640 39,599
Goodwill (Note 3) 8,509 8,509
-----------------------
$ 68,305 $ 52,741
-----------------------
-----------------------

LIABILITIES

Current
Bank facility (Note 5) $ 7,925 $ -
Accounts payable and accrued liabilities 6,880 5,394
Current portion of capital lease obligation - 35
-----------------------
14,805 5,429

Asset retirement obligation (Note 8) 1,613 1,079
Future income tax liability (Note 10) 4,784 5,787
-----------------------

$ 21,202 $ 12,295
SHAREHOLDERS' EQUITY

Share capital (Note 9 (b)) $ 47,464 $ 42,692
Contributed surplus (Note 9 (c)) 3,371 1,532
Deficit (3,732) (3,778)
-----------------------
47,103 40,446
-----------------------
$ 68,305 $ 52,741
-----------------------
-----------------------

Commitments (Note 13)
Subsequent events (Note 15)

See accompanying notes to the interim financial statements.


----------------------------------------------------------------------------
E4 Energy Inc.
Consolidated Statements of Operations and Deficit
Years ended December 31 (in thousands of Canadian dollars, except per share
amounts)
----------------------------------------------------------------------------


2006 2005
-----------------------
Revenue
Petroleum and natural gas $ 15,486 $ 16,202
Royalties (2,869) (2,750)
-----------------------

12,617 13,452

Expenses
Operating 2,892 2,528
Transportation 487 828
General and administrative (Note 4) 2,433 2,685
Financing charges (Note 7) 460 684
Depletion, depreciation and accretion 9,433 7,363
Loss on asset retirement - 97
Loss on disposal of equipment under capital lease - 87
-----------------------
$ 15,705 $ 14,272

Loss before taxes (3,088) (820)

Future income tax reduction (2,969) (1,124)
-----------------------

Net earnings (loss) (119) 304

Deficit, beginning of year (3,778) (4,082)

Stock options settled for cash 165 -
-----------------------

Deficit, end of year (3,732) (3,778)
-----------------------
-----------------------
Earnings (loss) per share
Basic and diluted $ (0.00) $ 0.01
-----------------------
-----------------------


See accompanying notes to the interim financial statements.


----------------------------------------------------------------------------
E4 Energy Inc.
Consolidated Statements of Cash Flow
Years ended December 31 (in thousands of Canadian dollars)
----------------------------------------------------------------------------

2006 2005
-----------------------
Cash provided from (used in):

Operating activities
Net earnings (loss) $ (119) $ 304
Items not affecting cash:
Stock-based compensation 1,190 815
Finance charges - 265
Depletion, depreciation and accretion 9,433 7,363
Loss on asset retirement - 97
Loss on disposal of equipment under capital lease - 87
Future income tax reduction (2,969) (1,124)
Asset retirement costs (33) (99)
Change in non-cash working capital (Note 11) (655) (2,014)

-----------------------

6,847 5,694

-----------------------
Financing activities
Proceeds from share issue, net of issue costs 6,506 9,608
Stock options exercised 108 637
Settlement of options (168) -
Issuance (repayment) of bank facility 7,925 (5,087)
Repayment of subordinated notes - (2,000)
Repayment of capital lease obligation (35) (200)
-----------------------

14,336 2,958
-----------------------

Investing activities
Corporate acquisition - 4,708
Property, plant and equipment additions, net of
disposals (22,798) (10,645)
Proceeds from disposal of subsidiary - 15
Change in non-cash working capital (Note11) 848 (1,921)
-----------------------
(21,950) (7,843)
-----------------------

Change in cash (767) 809

Cash, beginning of year 809 -
-----------------------

Cash, end of year $ 42 $ 809
-----------------------
-----------------------


Supplemental cash flow information (Note 11)

See accompanying notes to the interim financial statements.


E4 Energy Inc.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2006 and 2005


1. INCORPORATION AND NATURE OF OPERATIONS

Naneco Minerals Ltd. was continued under the laws of the Province of Alberta and changed its name to Southpoint Resources Ltd. ("the Company") on February 6, 2002. The Company at that time refocused its efforts to the exploration and development of petroleum and natural gas in Western Canada. On August 23, 2005, in conjunction with the business combination discussed in Note 3, the Company changed its name to E4 Energy Inc. ("E4"). E4 is involved in the exploration, development and production of petroleum and natural gas in Alberta and British Columbia.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The financial statements are stated in Canadian dollars and have been prepared in accordance with Canadian generally accepted accounting principles. The preparation of financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates.

Joint Operations

Substantially all of the exploration, development and production activities are conducted jointly with others and accordingly, the Company only reflects its proportionate interest in such activities.

Measurement Uncertainty

The amounts recorded for depletion and depreciation of petroleum and natural gas property, plant and equipment and the provision for asset retirement obligations are based on estimates. The cost recovery ceiling test is based on estimates of reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material.

Petroleum and Natural Gas Properties

The Company follows the full cost method of accounting for petroleum and natural gas operations, whereby all costs related to the acquisition, exploration and development of petroleum and natural gas reserves are capitalized. Such costs include lease acquisition costs, geological and geophysical costs, carrying charges of non-producing properties, costs of drilling both productive and non-productive wells, the cost of petroleum and natural gas production equipment and overhead charges related to exploration and development activities.

Petroleum and natural 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 cost of unproved properties, net of impairments, exceed the carrying value of the petroleum and natural gas assets. If the carrying value of the petroleum and natural gas assets is not assessed to be recoverable, an impairment loss is 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 and market of unproved properties. The cash flows are estimated using the future product prices and costs and are discounted using the risk-free rate.

Proceeds from the disposition of petroleum and natural gas properties are applied against capitalized costs except for dispositions that would change the rate of depletion and depreciation by 20 percent or more, in which case a gain or loss would be recorded.

Depletion and Depreciation

Capitalized costs, together with estimated future capital and retirement 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 relative energy content of six thousand cubic feet of gas to one barrel of oil. Costs of significant unproved properties, net of impairments, are excluded from the depletion and depreciation calculation.

Asset Retirement Obligations

The fair values of asset retirement obligations related to long-lived assets are recognized as a liability in the period in which they are incurred. Retirement costs equal to the fair value of the asset retirement obligations are capitalized as part of the cost of the associated long-lived assets. Subsequent to the initial recognition, the obligation is adjusted each period to reflect the passage of time (accretion) and changes in the estimated cash flows underlying the obligation.

Revenue Recognition

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

Income Taxes

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

Stock Based Compensation

The Company applies the fair value method of accounting to all equity-classified stock-based compensation arrangements for both employees and non-employees. Compensation cost of equity-classified awards to employees are measured at fair value at the grant date and recognized over their vesting period with a corresponding increase to contributed surplus. Compensation cost of equity-classified awards to non-employees are initially measured at fair value, and periodically remeasured to fair value until the non-employee's performance is complete, and recognized over their vesting period with a corresponding increase to contributed surplus. Upon the exercise of the award, consideration received together with the amount previously recognized in contributed surplus is recorded as an increase to share capital. The Company accounts for forfeitures as they occur.

Goodwill

Goodwill is recognized on corporate acquisitions when the total purchase price exceeds the fair value of the net identifiable assets of the acquired company. Goodwill is tested for impairment on an annual basis in the fourth quarter. If indications of impairment are present, a loss would be charged to earnings for the amount that the carrying value of goodwill exceeds its fair value.

Flow-through Shares

When flow-through shares are issued the proceeds are used to fund qualifying exploration and development expenditures within a defined time period and are renounced to investors in accordance with tax legislation. Share capital is reduced and the future income tax liability is increased by the estimated future income tax cost of the renounced tax deductions when the renouncement is made.

Per Share Amounts

Basic per share amounts are computed using the weighted average number of common shares outstanding during the reporting period. Diluted per share amounts are calculated using the treasury stock method, which assumes that any proceeds from the exercise of stock options in addition to the unrecognized amount of stock-based compensation costs are used to purchase common shares of the Company at the average market price during the reporting period.

3. BUSINESS COMBINATION

On August 23, 2005, the Company acquired all of the common shares of P3 Energy Ltd. ("P3"), a private oil and gas company, pursuant to an Amalgamation Agreement (the "Agreement"). The P3 shareholders received one E4 common share for each of the 10,779,600 P3 common shares formerly held by them. The shares issued to P3 shareholders were valued at $1.31 per share, which was the 5 day weighted average price of E4 shares prior to announcing this transaction, net of implied issue costs. In addition, the P3 directors, officers and employees, who continue to provide service to the Company, received one E4 stock option for each of the 623,000 P3 stock options formerly held by them at the same terms as the original P3 stock options. The acquisition date fair value of the replacement E4 stock options is $843,986. The earned portion of the replacement option fair value has been recognized as part of the purchase price consideration with the remainder to be amortized as stock based compensation over the remaining service period. The acquisition of P3 was accounted for using the purchase method of accounting. The results of operations of P3 have been included in the consolidated financial statements from the date of acquisition. The following table summarizes the purchase price allocation:



($ thousands)

Consideration:
Common shares 13,415
Stock options 148
Transaction costs 183
-------------
Total 13,746
-------------
-------------

Net assets acquired:
Cash 4,891
Working capital deficit (381)
Property, plant and equipment 6,042
Goodwill (without tax basis) 6,197
Asset retirement obligation (57)
Future income tax liability (2,946)
-------------
Total 13,746
-------------
-------------


4. PROPERTY, PLANT AND EQUIPMENT

($ thousands) 2006 2005
----------------------------------------------------------------------------
Petroleum and natural gas properties 82,299 57,938
Accumulated depletion and depreciation (27,659) (18,339)
----------------------------------------------------------------------------
Property, plant and equipment, net 54,640 39,599
----------------------------------------------------------------------------


During the year ended December 31, 2006, the Company capitalized $1.6 million of general and administrative costs (2005 - $0.7 million) related to exploration and development activities.

The calculation of 2006 depletion and depreciation included an estimated $5.0 million (2005 - $0.6 million) for future development and associated retirement costs associated with proved reserves and excluded $7.2 million (2005 -- $3.6 million) for the estimated value of unproved properties.

The prices used in the ceiling test evaluation of the Company's oil and gas assets are summarized in the following chart. Based on these assumptions, the undiscounted value of future net revenues from the Company's estimated proved reserves exceeded the carrying value of property, plant and equipment as at December 31, 2006.



Crude Oil and Natural Gas

----------------------------------------------------------------------------
West Texas Company price Company price per
Intermediate per reserve AECO Gas price reserve report
(Cdn$/bbl)(1) report (Cdn$/bbl) (Cdn$/mmbtu) (Cdn$/mcf)
----------------------------------------------------------------------------
2007 70.11 59.60 7.33 6.94
2008 68.97 59.20 7.91 7.58
2009 68.97 59.47 7.89 7.59
2010 66.67 57.55 7.87 7.58
2011 64.37 55.69 8.02 7.73
2012 65.66 57.47 8.19 7.95
2013 66.97 59.13 8.35 8.16
2014 68.31 61.66 8.52 8.44
2015 69.67 63.74 8.69 8.74
2016 71.07 67.91 8.86 8.94
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Thereafter (2) 2.0% 2.0% 2.0% 2.0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Future prices incorporated a $0.87 US/Cdn exchange rate.
(2) Percentage change of 2.0% represents the change in future prices each
year after 2017 to the end of the reserve life.


5. BANK FACILITY

The Company has an $18 million revolving term demand credit facility with a Canadian chartered bank. The credit facility provides that advances may be made by way of direct advances, bankers' acceptances or letters of guarantee. Direct advances bear interest at the bank's prime lending rate plus 0.125% . The credit facility is secured by a $50 million demand debenture secured by a first floating charge on all assets and a general assignment of book debts. The $18 million borrowing base is subject to an annual review by the bank, with the next review scheduled for late May 2007.

6. SUBORDINATED NOTES AND WARRANTS

On December 17, 2004, the Company issued subordinated notes in the amount of $2 million due in 18 months from the date of issuance that bore interest at a rate of 11 percent per annum. The subordinated notes carried a half detachable warrant for each $1.50 of principal with each whole warrant entitling the holder to acquire one common share of the Company at a price of $1.50 per share for a period of 18 months. The proceeds were allocated to the liability component (subordinated notes) and equity component (detachable warrants). The resulting discount on the notes of $0.3 million was being amortized over the term of the loan. In 2005, the subordinated notes were settled early at their face amount of $2 million resulting in a loss of $0.1 million. All warrants associated with these subordinated notes expired on June 17, 2006.



7. FINANCING CHARGES

Financing charges are comprised of the following:

----------------------------------------------------------------------------
($ thousands) Year ended December 31,
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------
Interest expense 460 420
----------------------------------------------------------------------------
Subordinated note finance change - 117
----------------------------------------------------------------------------
Loss on early retirement of subordinated note - 147
----------------------------------------------------------------------------
Total 460 684
----------------------------------------------------------------------------


8. ASSET RETIREMENT OBLIGATIONS

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 inflation adjusted amount of the estimated cash flows required to settle the asset retirement obligations is approximately $2.4 million which will be incurred over the next 23 years. A credit adjusted risk-free rate of eight percent was used to calculate the fair value of the asset retirement obligations. The following reconciles the Company's asset retirement obligations:



----------------------------------------------------------------------------
($ thousands) Year ended December 31,
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------
Balance, beginning of period 1,079 657
----------------------------------------------------------------------------
Liabilities incurred 327 111
----------------------------------------------------------------------------
Liabilities acquired on business combination - 57
----------------------------------------------------------------------------
Liabilities settled (33) (2)
----------------------------------------------------------------------------
Revisions 127 184
----------------------------------------------------------------------------
Accretion expense 113 72
----------------------------------------------------------------------------
Balance, end of year 1,613 1,079
----------------------------------------------------------------------------


9. SHARE CAPITAL

a) Authorized

Unlimited number of common shares.

b) Issued and outstanding

Common Shares
--------------
($ thousands) 2006
Shares Amount

Balance, beginning of year 38,671,338 $ 42,420
Flow-through common shares issued for cash 3,889,000 7,000
Exercise of stock options 83,334 142
Share issue costs, net of tax (344)
Tax effect on flow-through shares renounced (1,754)
------------ -----------
Balance, end of year 42,643,672 47,464

Balance warrants - December 31, 2005 666,667 272
Warrants expired on June 17, 2006 (Note 6) (666,667) (272)
-----------
Share Capital - Total $ 47,464
----------------------------------------------------------------------------

2005
Shares Amount
Balance, beginning of year 22,577,404 $ 18,813
Common shares issued for cash 2,662,000 5,058
Flow-through common shares issued for cash 2,129,000 5,216
Issued on acquisition of P3 10,779,600 13,415
Exercise of stock options 523,334 777
Share issue costs, net of tax (442)
Tax effect of flow-through shares renounced (417)
------------ -----------
Balance, end of year 38,671,338 42,420

Balance warrants - December 31, 2005 (Note 6) 666,667 272
-----------
Share Capital - Total $ 42,692
----------------------------------------------------------------------------

c) Contributed surplus

Contributed Surplus Continuity:
($ thousands) 2006 2005
Amount Amount

Balance beginning of year 1,532 441
Stock based compensation 1,935 1,082
Stock based compensation on acquisition of P3 (Note 3) - 148
Cash settlement of stock options (334) -
Stock options exercised (34) (139)
Warrants expired 272 -
----------------------
Balance, end of year 3,371 1,532
----------------------------------------------------------------------------


d) Flow-through shares

On October 20, 2005, the Company issued 2,129,000 flow-through common shares at a price of $2.45 per share for gross proceeds of $5.2 million. These expenditures were renounced to investors of this financing in 2005. Under the terms of the flow-through share agreement, the Company was committed to spend the gross proceeds on qualifying exploration expenditures prior to December 31, 2006. This commitment was fulfilled during 2006.

Prior to the acquisition date of P3 on August 23, 2005 (Note 3), P3 issued flow-through common shares for gross proceeds of $3.6 million. These expenditures were renounced to investors of this financing in 2005. As a result of the business acquisition, the Company had assumed the obligation to spend the gross proceeds on qualifying exploration and development expenditures prior to December 31, 2006. This commitment was fulfilled during 2006.

On November 30, 2006, the Company issued 3,889,000 flow-through common shares at a price of $1.80 per share for gross proceeds of $7.0 million. These expenditures were renounced to investors of this financing in 2006. Under the terms of the flow-through share agreement, the Company is committed to spend the gross proceeds on qualifying exploration expenditures prior to December 31, 2007. As at December 31, 2006, the Company had incurred approximately $0.6 million of qualifying expenditures.

e) Stock options

Under the Company's stock option plan, the Company may grant options to its directors, officers, employees and consultants to purchase common shares at a fixed price not less than their fair market value on the day preceding the grant date. The options vest at a rate of one-third on the six-month anniversary of the date of grant and a further one-third on each of the one-year and two-year anniversaries from the date of grant. The option's maximum term is five years. The following table sets forth a reconciliation of the stock option plan activity.



--------------------------
Weighted
2006 Average
----------
Exercise
Price
Options $
--------------------------
Balance, beginning of year 2,748,335 1.48
Granted 1,125,000 1.75
Settled (550,001) 1.44
Forfeited (22,667) 1.75
Expired (8,333) 1.75
Exercised (83,334) 1.30
--------------------------
Balance, end of year 3,209,000 1.58
--------------------------
--------------------------
Number of options exercisable 1,756,330 1.54
--------------------------
--------------------------

--------------------------
Weighted
2005 Average
----------
Exercise
Options Price
$
--------------------------
Balance, beginning of year 1,831,400 1.34
Granted 1,940,000 1.49
Forfeited (499,731) 1.36
Exercised (523,334) 1.22
--------------------------
Balance, end of year 2,748,335 1.48
--------------------------
--------------------------
Number of options exercisable 972,669 1.32
--------------------------
--------------------------

The following table summarizes stock options outstanding and exercisable
under the plan at December 31, 2006.

----------------------------------------------------------------------------
Options outstanding Options exercisable
----------------------------------------------------------------------------
Weighted
Number average Weighted Number Weighted
Range of outstanding remaining average exercisable average
exercise at contractual exercise at exercise
price period end life (years) price period end price
----------------------------------------------------------------------------

$ 1.00 to 928,000 3.11 1.10 618,668 1.10
$ 1.49
----------------------------------------------------------------------------
$ 1.50 to 2,281,000 3.81 1.78 1,137,662 1.78
$ 1.82
----------------------------------------------------------------------------
3,209,000 3.61 1.58 1,756,330 1.54
----------------------------------------------------------------------------

The fair-value of options granted during the period was estimated on the
date of grant using the Black-Scholes option pricing model with weighted
average assumptions and resulting values for grants as follows:

----------------------------------------------------------------------------
Weighted average assumptions and results 2006 2005
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Risk free interest rate (%) 3.90 3.64
----------------------------------------------------------------------------
Expected life 5.00 5.00
----------------------------------------------------------------------------
Expected volatility (%) 65.0 74.4
----------------------------------------------------------------------------
Fair value of options $ 1.01 $ 1.18
----------------------------------------------------------------------------


The Company recognized in 2006, $1.2 million of stock based compensation expense (2005 - $0.8 million). In addition, the Company capitalized $0.8 million of stock based compensation expense in 2006 (2005 -$0.3 million). The expensed portion of stock based compensation is reflected on the Company's consolidated statement of operations.

In January of 2006, the Company settled and cancelled an aggregate of 550,001 outstanding vested stock options with a weighted average strike price of $1.44, with its former employees. Total proceeds of $168,167 were paid to the former employees with respect to this settlement. The excess of the grant date fair value over the cash settlement has been recorded as a decrease to the deficit.

f) Share purchase loan

In conjunction with the flow-through share issue on December 30, 2004, the Company provided a share purchase loan in the amount of $48,000 to an employee secured by 30,968 common shares. As part of the business combination in Note 3 above, the share purchase loan was offset with the accrued liability for severance for this employee.

g) Earnings (loss) per share

The weighted average number of common shares outstanding during the year ended December 31, 2006 used in computing both basic and fully diluted loss per share was 39,095,077. Excluded from the fully diluted weighted average number of common shares outstanding at December 31, 2006 were 2,708,667 stock options that were anti-dilutive. The weighted average number of common shares outstanding during the year ended December 31, 2005 was 27,557,342 used in computing basic earnings per share. In calculating diluted earnings per share for the year ended December 31, 2005, 65,538 shares were added to the weighted average number of basic common shares outstanding. Excluded from the fully diluted weighted average number of common shares outstanding at December 31, 2005 were 2,983,068 stock options that were anti-dilutive.

10. FUTURE INCOME TAXES

The provision for future income taxes in the statements of earnings and retained earnings reflect an effective tax rate, which differs from the expected statutory tax rate. Differences were accounted for as follows:




----------------------------------------------------------------------------
($ thousands) 2006 2005
------------ -----------

Net loss before income taxes (3,089) (820)
Statutory income tax rate 35.1% 38.1%
Expected income taxes (1,084) (312)

Add (deduct):
Non-deductible crown charges 218 580
Resource allowance (257) (558)
Stock based compensation 418 400
Change in tax rates (829) (24)
Change in valuation allowance (1,436) (1,344)
Other 1 134
------------ -----------
Future income tax reduction (2,969) (1,124)
----------------------------------------------------------------------------

The future income tax liability at December 31, 2006 and 2005 is comprised
of the tax effect of temporary differences as follows:

----------------------------------------------------------------------------
($ thousands) 2006 2005
------------ -----------

Property, plant and equipment (6,623) (7,541)
Asset retirement obligations 473 363
Losses 1,107 1,186
Share issue costs 259 205
------------ -----------
Future income tax liability (4,784) (5,787)
----------------------------------------------------------------------------

Of the $1.1 million in losses in the table above, $0.4 million will expire
by 2010 and $0.4 million will expire by 2015.

11. SUPPLEMENTAL CASH FLOW INFORMATION

a) Increase (decrease) in non-cash working
capital items ($ thousands) Year ended December 31,
2006 2005
----------------------------------------------------------------------------
Change in non-cash working capital:
Accounts receivable 1,246 174
Prepaid expenses and deposits 45 63
Accounts payable and accrued liabilities (1,484) (4,163)
Working capital of subsidiary sold - (9)
-----------------------
(193) (3,935)
-----------------------
-----------------------
Changes in non-cash working capital related to:
Operating activities 655 (2,014)
Investing activities (848) (1,921)
-----------------------
(193) (3,935)
-----------------------
-----------------------

b) Interest ($ thousands) Year ended December 31,
2006 2005
----------------------------------------------------------------------------
Interest paid 418 420


12. FINANCIAL INSTRUMENTS

Fair value of financial assets

Cash, accounts receivable, deposits, accounts payable and accrued liabilities, bank facility and capital lease obligations constitute the Company's financial instruments. Based on their short-term maturities or market rates of interest, the carrying values of these financial instruments approximate their fair values at December 31, 2006 and 2005.

Credit risk

The Company's petroleum and natural gas production is marketed to a variety of different purchasers to mitigate such credit risk.

Accounts receivable are with customers and joint venture partners in the petroleum and natural gas business under normal industry sale and payment terms and are subject to normal industry credit risks. The Company routinely assesses the financial strength of its customers. The Company generally extends unsecured credit to customers and, therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which credit has been extended. The Company has not experienced any material credit loss in the collection of accounts receivable.

Interest rate risk

The Company is exposed to interest rate risk to the extent that changes in market interest rates will impact the Company's debts that have a floating interest rate. The Company had no interest rate swaps or hedges at December 31, 2006.

13. COMMITMENTS

The Company is committed to incur approximately $6.4 million prior to December 31, 2007 on qualifying exploration and development expenditures relating to the flow-through common share financing of November 30, 2006 (see Note 10 (d)).

At December 31, 2006, the Company has committed to certain payments over the next two years as follows:



-------------
Office Rental
----------------------------------------------------------------------------
2007 2008
----------------------------------------------------------------------------
($ thousands) 189 142
----------------------------------------------------------------------------


In addition to these amounts, the Company is responsible for its proportionate share of operating costs pertaining to the noted office facilities, which are periodically reviewed and determined by the landlord.

14. RELATED PARTY TRANSACTIONS

A director of the Company is a partner at a law firm that provide legal services to the Company. During the year ended December 31, 2006, the Company paid a total of $0.05 million to this firm for legal fees and disbursements. An additional amount of $0.04 million was accrued for at December 31, 2006 and subsequently paid in 2007. During the year ended December 31, 2005, the Company paid and accrued a total of $0.1 million to the same law firm.

15. SUBSEQUENT EVENTS

On January 31, 2007, the Company entered into a firm fixed price agreement with one of its natural gas purchasers. The term of the agreement is such that the first 1,500 gigajoules per day from the Company's McMahon receipt station will have a fixed price of $7.40 per gigajoule. This contract commences on April 1, 2007 and continues until October 31, 2007.

The TSX Venture Exchange does not accept responsibility for the adequacy or accuracy of this release.

Contact Information

  • E4 Energy Inc.
    Paul Starnino
    President and Chief Executive Officer
    (403) 266-6747
    Email: pstarnino@e4energy.ca
    or
    E4 Energy Inc.
    Franco Civitarese
    Vice President, Finance and Chief Financial Officer
    (403) 266-6747
    Email: fcivitarese@e4energy.ca
    or
    E4 Energy Inc.
    Head Office
    540, 840 - 6th Avenue S.W.,
    Calgary, Alberta, T2P 3E5
    (403) 266-6740 (FAX)
    Website: www.e4energyinc.ca