Exhibit 99.1

September 15, 2010

Mr. Jeff Johnson

Cano Petroleum, Inc.

Burnett Plaza

801 Cherry Street

Unit 25, Suite 3200

Fort Worth, TX 76102

Dear Mr. Johnson:

As requested, Haas Petroleum Engineering Services, Inc. (hereinafter referred to as “HPESI”) has prepared an estimate of certain hydrocarbon Reserves owned by Cano Petroleum, Inc. (hereinafter referred to as “Cano”).  The properties evaluated in this report are located in New Mexico, Oklahoma, and Texas.  As of June 30, 2010, Cano’s net shrunk Reserves, future net income (“FNI”), and net present worth discounted at 10 percent per annum (“NPV”) have been estimated in table below.  A by-field breakdown of each reserve category can be found in Appendix A in this report.

TABLE 1

* Totals in Table 1 may not exactly match values in the attached cash flow summaries and tabular summaries due to computer rounding.

FNI is after deducting estimated operating and future development costs, severance and ad valorem taxes, but before Federal income taxes.  Total net Proved, Probable, and Possible Reserves are defined as those shrunk natural gas and hydrocarbon liquid Reserves to Cano’s interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances.  All Reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and

conform to guidelines developed and adopted by the United States Securities and Exchange Commission (“SEC”).  All hydrocarbon liquid Reserves are expressed in United States barrels (“bbl”) of 42 gallons.  Natural gas Reserves are expressed in thousand standard cubic feet (“Mcf”) at the contractual pressure and temperature bases.

RESERVES ESTIMATE METHODOLOGY

The Reserves estimates contained in this report have been prepared using standard engineering practices generally accepted by the petroleum industry.  Decline curve analysis was used to estimate the remaining Reserves of pressure depletion reservoirs with enough historical production data to establish decline trends.  Reservoirs under non-pressure depletion drive mechanisms and non-producing Reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both.  The maximum remaining Reserves life assigned to wells included in this report is 40 years.  This report does not include any gas sales imbalances.

RESERVES CLASSIFICATION

The Reserves estimates included in this report conform to the guidelines specified by the SEC.

·                  Proved developed reserves are those quantities of crude oil, condensate, and natural gas which can be expected to be recovered in future years through existing wells under existing economic and operating methods.

·                  Proved developed producing reserves are expected to be produced from existing completion interval(s) now open for production in existing wells.

·                  Proved developed non-producing reserves included shut-in and behind-pipe reserves.  Shut-in reserves are expected to be recovered from completion intervals open at the time of the estimate, but which had not started producing.  Behind-pipe reserves are expected to be produced through the existing wells in the predictable future, and the cost of placing these reserves on production should be relatively small compared to the cost of a new well.

·                  Proved undeveloped reserves are expected to be recovered from the new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonable certain of production when drilled.  Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of productive formation.

·                  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered.

·                  Possible reserves include those additional reserves that are less certain to be recovered than probable reserves.  There must be at least a 10% probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates.

COMMODITY PRICES

The cashflow projections in this report utilize the un-weighted arithmetic 12 month average of the first-day-of-the month natural gas and oil prices for July 2009 through June 2010.  The un-weighted average cash market price for natural gas delivered at the Henry Hub during this time period is $4.10/MMBTU and $75.76/bbl of oil.

Historical hydrocarbon liquid prices were indexed to the monthly average of the daily closing prices received at the Cushing, Oklahoma delivery point.  The average difference between the wellhead oil

2

price and the NYMEX price represents adjustments for crude quality, marketing fees, BS&W, transportation costs and purchaser bonuses.  These adjustments were applied to the un-weighed arithmetic 12 month average of the first-day-of the month prices for July 2009 through June 2010.

Historical natural gas prices were indexed to the monthly Henry Hub prices posted in the Inside FERC publication.  Historical prices were indexed for each month of available accounting data.  The average difference between the wellhead price and the NYMEX price represents adjustments for BTU content, marketing, and transportation costs.  These adjustments were applied to the un-weighed 12 month arithmetic average of the first-day-of the month prices for July 2009 through June 2010.

OPERATING EXPENSES & CAPITAL COSTS

In most cases, the lease operating costs used in this evaluation represent the average of recent historical monthly operating costs and were modeled with both a fixed and variable component.  In cases where historical costs were not available or deemed to be unreliable, operating costs were estimated based on knowledge of analogous wells producing under similar conditions.  The lease operating expenses in this report represent field level operating costs and do not include COPAS charges.

Where available, capital costs were estimated using recent historical information reported for analogous expenditures.  Where recent historical information was not available, Authority for Expenditure (“AFE”) documents were used to estimate capital costs.  AFE documents provided by the operator have been checked for reasonableness.  For the purpose of this report, salvage value for each project was assumed to be equal to the abandonment costs.

Pursuant to SEC guidelines, operating expenses and capital costs were not escalated in this evaluation.

DISCLAIMERS

All information pertaining to the operating expenses, prices, and the interests of Cano in the properties appraised has been accepted as represented.  It was not considered necessary to make a field examination of the appraised properties.  Data used in performing this appraisal were obtained from Cano, public sources, and our own files.  Supporting work papers pertinent to the appraisal are retained in our files and are available to you or designated parties at your convenience.

It was beyond the scope of this HPESI report to evaluate the potential environmental liability costs from the operation and abandonment of these properties.  In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements.  Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the forecasts presented herein.

The Proved, Probable, and Possible Reserves presented in this report are estimates only and should not be construed as being exact quantities.  They may or may not be actually recovered; and, if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts.  Because of governmental policies and uncertainties of supply and demand, the product prices and the costs incurred in recovering these Reserves may vary from the price and cost assumptions in this report.  In any case, quantities of Proved, Probable, and Possible Reserves may increase or decrease as a result of future operations.

3

Undeveloped wells’ capital costs associated with the Waterflood were assigned to the Waterflood line item, rather than the individual cases.

As requested, some of the producing properties were allowed to run uneconomically until the Non-PDP Waterflood reserves reached economic rates.

HPESI acknowledges that additional value may be associated with a new pipeline construction at Nowata.  Currently, the casing head gas is being vented; the new pipeline will tie this gas into the existing sales line.  The reserves and revenue are not currently included in this report.

The SEC requires a development plan be in place for these assets.  This reserve report defines a budget for that development plan, but HPESI makes no representation about the company’s ability to fund this development.

CONCLUSIONS

Attached are summary tables of economic analysis of predicted future performance. Other tables identify the properties appraised with summary Reserves and the economic factors applicable to each.  A list of tables is included.

We appreciate this opportunity to have been of service and hope that this report will fulfill your requirements.

4