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Liquidity and Capital Resources

Exall has a revolving demand credit facility with a Canadian chartered bank for $6.5 million that bears interest at the lender's base prime rate plus 1.25 percent which is reviewed periodically by the bank. In addition, Exall has a fixed demand credit facility with a private merchant bank for $2.0 million that bears interest at the 12.5 percent which is due May 31, 2010.

At March 31, 2010, the Company had approximately $4.4 million outstanding on its revolving credit facility, $1.75 million outstanding on its fixed credit facility and an approximate working capital deficiency of $2.3 million for total net debt of approximately $8.4 million. On March 22, 2010 and April 05, 2010 Exall announced that it has raised gross proceeds of $3,704,903 by way of a brokered private placement through D & D Securities Company. The net funds from the financing and cash flow from operations during the first quarter of 2010 were used to fund the Company's winter drilling program. Cash flows from increased production levels in 2010 will be used to reduce Exall's working capital deficiency and fund the balance of the Company's 2010 capital program.

During the period ended March 31, 2010, the Company used bank debt, the merchant bank facility, and cash flow from operations to fund capital expenditures and other requirements. For the nine months remaining in fiscal 2010, the Company's capital expenditures will be limited by the cash flow available from operations, additional debt or equity as market conditions may allow and potential asset sales if the Company so chooses.

Capital Expenditures

Oil and gas exploration and development expenditures were $5,334,772 for the first quarter of 2010 as compared to $533,016 for the first quarter of 2009. During the first quarter of 2010 the Company participated in drilling of 1.0 gross well (0.73 net) in the Marten Mountain / Mitsue area, which was a dual leg horizontal well and 1.0 gross well (0.66 net), which was a single leg horizontal well. The Company acquired 2,600 gross (1,716 net) acres of undeveloped land in the Mitsue area. The Company has 17,451 acres (10,217 acres net) of undeveloped land in Canada.

Outlook

In January 2010 Exall announced the completion and commissioning of an oil production pipeline and battery facilities, and the approval of the waterflood project and Good Production Practice (GPP) status for the wells in the Marten Mountain area of Alberta. All facilities and all approvals were in place and the project was on stream at full rates in February 2010. The proven reserves and production capability established by the wells are expected to increase the corporate cash flow and borrowing power sufficiently to fund further development of that key property, as well as other assets owned by the Company.

Exall has focused its capital in development of the Marten Mountain Prospect area. A "B" Sand prospect as previously announced by Exall was drilled as a horizontal well. Over a three day test period the well flowed 600 barrels of 40° API sweet oil and 110 MCFPD of solution gas (620 BOEPD, 445 BOEPD net). The well is immediately adjacent to the Exall pipeline completed in Q4 of last year and is already completed and tied and on production.

A Marten Mountain "A" Sand extension test well was also drilled, as a multi-lateral horizontal well from a common cased wellbore. The well penetrated both "A" and "B" sands with encouraging hydrocarbon shows in both zones on initial completion. A work-over program is planned for the well this summer once permanent access is established.

The wells drilled this winter have established continued sand development on the original Marten Mountain sand trend as well as a new trend with all-weather access. A number of offset drilling opportunities have been identified by the wells and, as the drilling rig was racked on site, the first well will be spud immediately after breakup. Exall plans to drill two to four wells on the "B" Sand trend through the summer as well as two additional wells on the "A" Sand trend after freeze-up next winter. The ability to continue development of this key property through the summer is an exciting change for the Company as access to new drilling had been limited to winter season until discovery of the "B" Sand trend. Summer access will allow Exall to accelerate development plans in the Marten Mountain area.

A major challenge over the past year has been the imposition of the New Royalty Framework ("NRF") in Alberta. Changes have been introduced to the NRF by the Government of Alberta, including Transitional Royalty rates and drilling incentives, with the objective of alleviating the excessive royalty burden of the NRF and to spur drilling have improved the economics of drilling activity in the province. The Government of Alberta has made some significant permanent changes in the Modified Royalty Framework ("MRF") which has several features which will directly affect the future of Exall. The most significant of the changes to Exall are:

1. The reduction of maximum royalty rate paid on high-rate oil wells from 50 percent to 40 percent starting in January 2011. This change will have a direct impact on the cash flow of Exall. The two Marten Mountain wells currently producing on GPP have been subject to the 50 percent maximum royalty rate since they went on production. The 10 percent reduction at $80 per barrel adds $8 to the operating netback, currently about $35 per barrel, bringing it to $43 per barrel.

2. Continuation of the 5 percent cap on royalties for the first year or first 50,000 barrels of oil as a permanent program. Netbacks for new wells producing under this program are expected to be over $70 per barrel. Although this program was already in place, the Government has now made assurances that this will be a permanent feature in the Modified Royalty Framework. After the first 50,000 barrels produced new oil wells will be subject to a maximum royalty of 40 percent.

3. Continuation of the Drilling Credits of $200 per meter to the end of its proposed term at April 1, 2011. Again, this was already in place but we now have the certainty for the planning of the next winter season drilling program.

Completion of the waterflood approval and facilities construction phase has precipitated a jump in production rates and cash flow for the Company starting in January 2010. With the continued drilling success Exall has managed to finance activities through cash flow, increased debt and limited equity issues. The new Modified Royalty Framework provides the necessary incentive to continue to aggressively exploit the high-productivity light, sweet oil assets the Company holds in the Marten Mountain property.

Exall is a light oil-weighted company with high operating margins. Starting from a modest production base of light oil and gas, the Company has shown itself capable of setting and achieving ambitious production and cash flow targets. This puts the Company in a favorable position to exploit existing opportunities and potentially take advantage of opportunities that arise. Exall will continue to focus on organic growth through exploitation and expansion of its existing oil producing properties.

About Exall

Exall is a junior oil and gas company active in its business of oil and gas exploration, development and production from its properties in Alberta, British Columbia and Texas. Exall Energy is currently developing the new Mitsue area "Marten Mountain" discovery in north-central Alberta.

Exall Energy currently has 52,147,745 common shares outstanding. The Company's common shares are listed on the Toronto Stock Exchange under the trading symbol EE.

Reader Advisory

This news release contains forward-looking statements, which are subject to certain risks, uncertainties and assumptions, including those relating to results of operations and financial condition, capital spending, financing sources, commodity prices and costs of production. By their nature, forward-looking statements are subject to numerous risks and uncertainties that could significantly affect anticipated results in the future and, accordingly, actual results may differ materially from those predicted. A number of factors could cause actual results to differ materially from the results discussed in such statements, and there is no assurance that actual results will be consistent with them. Such factors include fluctuating commodity prices, capital spending and costs of production, and other factors described in the Company's most recent Annual Information Form under the heading "Risk Factors" which has been filed electronically by means of the System for Electronic Document Analysis and Retrieval ("SEDAR") located at [ www.sedar.com ]. Such forward-looking statements are made as at the date of this news release, and the Company assumes no obligation to update or revise them, either publicly or otherwise, to reflect new events, information or circumstances, except as may be required under applicable securities law.

For the purposes of calculating unit costs, natural gas has been converted to a barrel of oil equivalent (boe) using 6,000 cubic feet equal to one barrel (6:1), unless otherwise stated. The boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore boe may be misleading if used in isolation. This conversion conforms to the Canadian Securities Regulators' National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.