Exhibit 99.1

January 10, 2011

Mr. Shawn McWilliams
Business Unit Controller
Ramshorn Investments, Inc.
515 W. Greens Road, Suite 1000
Houston, Texas 77067-4525

		Re:		Ramshorn Investments, Inc.
				Proved Reserves and
				Future Net Revenues
				As of December 31, 2010
				SEC Price Case

Dear Mr. McWilliams:

     As requested, Miller and Lents, Ltd. (MLL) estimated the proved reserves and projected the future net revenues attributable to the interests of Ramshorn Investments, Inc. (Ramshorn) as of December 31, 2010. This report was prepared for Ramshorn’s use for reserves and financial planning and completed on January 7, 2011. The estimates were made in accordance with the definitions contained in Securities and Exchange Commission (SEC) Regulation S-X, Rule 4-10(a) as shown in the Appendix. The aggregate results are shown in the following table. In this table and for some summaries herein, MLL consolidated natural gas liquids (NGLs), oil, and condensate together as hydrocarbon “liquids”.

Reserves and Future Net Revenues as of December 31, 2010

		Net Reserves								Future Net Revenues
														Discounted at
		Liquids,				Gas,				Undiscounted,				10% Per Year,
Reserves Category		MBbls.				MMcf				M$				M$
Proved Producing			213.0				14,906.3				38,594.0				20,972.0
Proved Nonproducing			53.8				2,146.2				8,224.0				4,449.7
Total Proved Developed			266.8				17,052.5				46,818.0				25,421.7
Proved Undeveloped			22.4				2,715.2				7,097.3				2,335.6
Total Proved			289.2				19,767.7				53,915.3				27,757.3

     Future net revenues as used herein are defined as the total revenues attributable to the evaluated interest less royalty, production taxes, operating expenses, and future capital expenditures. Future net revenues were discounted at 10 percent and do not include deductions for federal income tax. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.

Two Houston Center • 909 Fannin Street, Suite 1300 • Houston, Texas 77010
Telephone 713-651-9455 • Telefax 713-654-9914 • e-mail: mail@millerandlents.com

Mr. Shawn McWilliams		January 10, 2011
Ramshorn Investments, Inc.		Page 2

     The evaluated wells are in numerous domestic fields and areas located in the states of Arkansas, Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Utah, and Wyoming. Ramshorn’s interest in the properties consists of nonoperated working interests, overriding royalty interests, or mineral interests. Ramshorn has little information on the properties other than financial statements from the operators showing allocated revenues and costs. For our evaluations, MLL used monthly summary data since October 2007 that have been accumulated by Ramshorn from these financial statements, supplemented by information from public records and commercial data services.

     The nonproducing and undeveloped wells included in MLL’s evaluation were limited to properties with adequate technical data and development plans to evaluate such opportunities. Some of the Ramshorn properties may have additional behind pipe and/or undeveloped reserves but were not included herein due to lack of readily available information. Ramshorn reportedly has interests in some additional wells that were not included herein because MLL found no production records for them either from revenue statements or public sources. Some of these wells may be recently drilled or not yet on production; others may be wells that are not commercially productive. It is possible that some of the wells are actually producing now, but data were not yet available at the time of MLL’s evaluation.

Production Data

     Wherever possible, MLL used the complete monthly history of production available from commercial services for our evaluation of each property. For those properties on which we found little or no production data, MLL used recent monthly production data provided by Ramshorn. On the properties that showed “plant products” production from the information provided by Ramshorn, MLL estimated natural gas liquids recovery ratios and gas shrinkage factors. Generally, MLL projected the major phase (oil or gas) based on the decline curve trend for each property or based on analogy with wells in the same field or area. Condensate yields, gas-oil ratios, NGL yields, and gas shrinkage factors were estimated and projected from the available data to forecast the secondary products.

Prices

     The prices used for the 2010 reserves projections herein are in accordance with SEC standards. The oil price of $79.43 per barrel and gas price of $4.376 per MMBtu represent the twelve-month average of the first-day-of-the-month price for each month within the twelve month period prior to December 31, 2010 as shown in Table 1. MLL assumed an NGL price equal to 60 percent of the oil price. Price differentials for each property were determined by comparing the actual average monthly oil, gas, and NGL price based on monthly production and revenue data provided by Ramshorn to the monthly benchmark prices of these products. The computed differentials were then used as multiplier ratios for each product to adjusted benchmark prices. For properties on which available data were insufficient to calculate price differentials, MLL used the average price multiplier that we had calculated for Ramshorn properties in the same field or state. The actual average product prices for

Mr. Shawn McWilliams		January 10, 2011
Ramshorn Investments, Inc.		Page 3

proved reserves in this report, after appropriate adjustments, were $61.12 per barrel for oil, $36.43 per barrel for NGLs, and $3.72 per Mcf for gas.

Operating Costs

     For working interest properties, MLL estimated current average operating costs per well per month for each property based on the historical information provided by Ramshorn. For mineral interests, overriding royalty interests, and wells for which cost data were not available, MLL estimated monthly operating costs per well per month based on analogy or experience for properties in nearby areas. Although no operating costs were incurred for overriding royalty or mineral interests, an estimate of operating cost was needed to determine the economic producing limit. MLL held operating costs constant for all future years.

Ownership Interests

     Ramshorn provided a list of the net working interest and net revenue interest that it carried for each property. For some wells, the working interest or net revenue interest was unknown. For properties on the list with working interests shown but where Ramshorn’s net revenue interest was unknown, MLL estimated net revenue interests based on a 0.75 ratio of net revenue interest to working interest. The 0.75 ratio was selected because it best represented the actual average ratio for many of Ramshorn’s working interest properties. For properties on the list with no working interest and modest net revenue interests, MLL assumed Ramshorn holds an overriding royalty or mineral interest only. Some of the properties have ceased to produce or are producing at rates below the estimated economic limit. They are included herein, but remaining reserves and future net revenues for these properties were reported as zero. Properties on which MLL had interest data but for which we could not find production data were excluded from this report.

     Interest reversions were scheduled based on payout criteria and balances provided by Ramshorn. MLL assumed no production balancing provisions exist for the Ramshorn properties as no relevant information was available.

Reserves Projections

     Forecasts of future production were made for each property based on historical trend or analogy. Reserves were determined as the sum of the forecast production for all months after December 31, 2010 until the economic producing limit was reached for each property. For properties with short or erratic production histories, there is greater uncertainty in the projection of future production than for properties with long histories of production on a consistent decline trend. Gas reserves are reported at the appropriate pressure and temperature base for each state; therefore, the consolidated total is at a mixed pressure base.

Mr. Shawn McWilliams		January 10, 2011
Ramshorn Investments, Inc.		Page 4

Attachments

     Table 1 shows the first-day-of-the-month price for each month within the twelve month period prior to December 31, 2010 used to calculate the SEC twelve month average prices used in the MLL’s projections. Figure 1 is a pie chart showing reserves and discounted future net revenues by state. In preparing this chart, MLL used an equivalence factor of 6 Mcf of gas per barrel of hydrocarbon liquid (oil or NGLs).

     Exhibits 1 through 15 are cash flows and one-line summaries grouped as requested by Ramshorn. Exhibit 1 shows the total cash flow summary for total proved reserves. Exhibits 2, 3, and 4 show cash flow summaries by reserves category. Exhibits 5 through 12 show cash flow summaries sorted by state. Exhibits 13, 14, and 15 are one-line summaries of individual wells sorted by state, alphabetic order, and descending future net revenues, respectively.

     As an aid to property identification, the numerical Well Code assigned by Ramshorn to its properties is shown on the exhibits in addition to the entity name.

Other Considerations

     As instructed by Ramshorn, MLL used an abandonment cost of $40,000 per well, which was applied when each well reached its economic limit. In some cases, application of this abandonment cost causes the undiscounted future net revenues to be negative. These wells were included in our summary with their negative values.

     Future costs of abandoning facilities and any future costs of restoration of producing fields to satisfy environmental standards were not deducted from total revenues, as such estimates are beyond the scope of this assignment.

     In conducting this evaluation, MLL relied upon production, revenue, cost, and ownership data supplied by Ramshorn and upon nonconfidential data from public records or commercial data services. These data were accepted as represented and considered appropriate for the purpose served by the report.

     MLL applied all methods, procedures, and assumptions it considered necessary and appropriate under the circumstances in using the data provided to prepare this report.

     The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect MLL’s informed judgments and are subject to the inherent uncertainties associated with interpretation of geological, geophysical, and engineering information. These uncertainties include but are not limited to the utilization of indirect or imprecise data and the application of professional judgment in performing these evaluations. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this

Mr. Shawn McWilliams		January 10, 2011
Ramshorn Investments, Inc.		Page 5

report. At this time, MLL is not aware of any regulations that would affect Ramshorns’s ability to recover the estimated reserves. Minor precision inconsistencies in subtotals may exist in the report due to truncation or rounding of aggregated values.

     Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in Ramshorn or any affiliated company. MLL’s compensation for the required investigations and preparation of this report is not contingent on the results obtained and reported, and we have not performed other work that would affect our objectivity. Production of this report was supervised by Carl D. Richard, an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 25 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

		Very truly yours,
		MILLER AND LENTS, LTD.
		Texas Registered Engineering Firm No. F-1442
		By		Carl D. Richard, P.E.
				Senior Vice President

CDR/eb

Appendix
Page 1 of 3

Reserves Definitions In Accordance With
Securities and Exchange Commission Regulation S-X

Reserves

     Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

     Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Proved Oil and Gas Reserves

     Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

1.

The area of the reservoir considered as proved includes:

	a.		The area identified by drilling and limited by fluid contacts, if any, and
	b.		Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

	2.		In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
	3.		Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
	4.		Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

	a.		Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
	b.		The project has been approved for development by all necessary parties and entities, including governmental entities.

Appendix
Page 2 of 3

5.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed Oil and Gas Reserves

     Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

	1.		Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
	2.		Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped Oil and Gas Reserves

     Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

	1.		Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
	2.		Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
	3.		Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined below, or by other evidence using reliable technology establishing reasonable certainty.
			Analogous Reservoir

     Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

	1.		Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
	2.		Same environment of deposition;
	3.		Similar geological structure; and
	4.		Same drive mechanism.

     Reservoir properties must, in aggregate, be no more favorable in the analog than in the reservoir of interest.

Appendix
Page 3 of 3

Probable Reserves

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

	1.		When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
	2.		Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
	3.		Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
	4.		See also guidelines in Items 4 and 6 under Possible Reserves.

Possible Reserves

     Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

	1.		When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
	2.		Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
	3.		Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
	4.		The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
	5.		Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
	6.		Pursuant to Item 3 under Proved Oil and Gas Reserves, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.