Exhibit 99.4

January 18, 2012

NFR Energy LLC

1415 Louisiana Street, Suite 1600

Houston, Texas 77002

Attention: Mr. Todd Levesque

Re: Proved Reserves and

Future Net Revenues

As of December 31, 2011

SEC Case

Gentlemen:

As requested, Miller and Lents, Ltd. (MLL) estimated the reserves and projected the future net revenues attributable to the interests of NFR Energy LLC (NFR) in certain oil and gas properties located primarily in East Texas, Montana, and Utah as of December 31, 2011. The report was prepared for NFR’s use in reserves and financial reporting and planning and was completed on January 16, 2011. The aggregate results of our evaluations, using constant product prices determined under Securities and Exchange Commission (SEC) guidelines for year-end 2011 are summarized below.

Reserves and Future Net Revenues as of December 31, 2011

Reserves Category	Net Reserves						Future Net Revenues
	Oil, MBbls.		NGL, MBbls.		Gas, MMcf		Undiscounted, M$		Discounted at 10% Per Year, M$
Proved Producing		1,812.5		8,719.3		398,424.9		1,435,795.4		710,037.8
Proved Nonproducing		585.4		1,625.5		116,533.5		320,049.8		130,438.9
Proved Undeveloped		3,477.2		15,684.5		655,058.2		1,620,845.3		328,793.2
Total Proved		5,875.1		26,029.3		1,170,016.6		3,376,690.5		1,169,269.9

Definitions

The reserves reported herein are in accordance with the definitions contained in SEC Regulation S-X, Rule 4-10(a) as shown in Appendix 1. Prices used herein and that are shown in Table 1 represent the 12-month average of the first-day-of-the-month price for each month within the 12-month period prior to December 31, 2011 as required by SEC guidelines.

Future net revenues, as used herein, are defined as the total gross revenues less royalty, production taxes, operating costs, and capital expenditures. Future net revenues do not include

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Attention: Mr. Todd Levesque	Page 2

deductions for federal income tax. The future net revenues were discounted at 10 percent per year (referenced later herein as “discounted future net revenues”) in accordance with SEC guidelines and to illustrate the time value of future cash flows. 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.

Reserves Considerations

NFR has advised us that MLL’s estimates herein represent 100 percent of its proved booked reserves for year-end 2011. All reserves are in the United States and are grouped into two geographic divisions. The properties in NFR’s East Texas Division evaluated herein are located primarily in East Texas, but one lease is in western Louisiana. The properties in NFR’s Rockies Division include several fields in north-central Montana and one field in Utah. Reserves projected for the East Texas area are generally from reservoirs at depths below 7,000 feet that produce gas with modest condensate yields. Reserves projected for the Montana properties are generally from reservoirs shallower than 3,000 feet and produce dry gas. Reserves projected for the Utah properties are from reservoirs at depths below 8,000 feet and typically produce gas with low condensate yields. Discussion of the properties in NFR’s two divisions follows.

East Texas Division

In the East Texas area, numerous reservoirs are productive. The zones are primarily gas-bearing, have very low average permeabilities, and range in depth from approximately 7,000 feet to more than 14,000 feet. Reservoirs include (from shallowest to deepest) Pettit, Travis Peak, Upper Cotton Valley, Lower Cotton Valley, Bossier, Haynesville, and Cotton Valley Lime. Recent development in these reservoirs has been with horizontal wells with large multi-stage hydraulic fracture treatments.

NFR is planning horizontal wells for essentially all future Haynesville shale development and undeveloped Cotton Valley areas. Typically, future NFR planned horizontal wells are projected to have lateral lengths of 3,500 feet or more (unless restricted by lease geometry) and oriented perpendicular to the main fracture plan in the reservoir. Hydraulic fracture stages spaced about 250 feet apart along the laterals are planned. Current spacing between horizontal laterals is expected to be 600 feet.

Reserves for existing wells were based on extrapolation of production performance generally using hyperbolic decline curves to a minimum exponential decline rate of five percent per year.

Future Haynesville horizontal well reserves and production profiles are based on average performance trends from NFR wells, adjusted for the expected lateral length, net pay thickness, and well density currently planned for the subject leases. NFR operates approximately 40 horizontal Haynesville wells in their leased areas. Information such as lateral length, pay thickness, number of fracture stimulation stages, fracture proppant concentrations and initial producing rate, were combined and correlated against the estimated ultimate recovery (EUR) for these wells. These correlations were

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segmented by area and used to estimate the initial producing rates and reserves for undeveloped Haynesville wells in those areas. All future NFR Haynesville development will be horizontal drilling with lateral wells spaced 600 feet apart. MLL did not consider any interference effects for this spacing due to the simultaneous fracture stimulation techniques being employed by NFR going forward.

Future Cotton Valley horizontal (CV HRZ) well reserves and production profiles were based on models built to compare the actual performance and future extrapolation of horizontal wells (adjusted for lateral length and number of fracture stages) with actual performance and future extrapolation of adjacent Cotton Valley vertical (CV VERT) wells. For reserves for CV HRZ wells drilled in areas where drainage from producing CV VERT wells is likely to occur, a well drainage area was calculated and applied as an interference factor to arrive at a depletion-adjusted EUR.

Condensate yields were projected based on actual yields reported for NFR wells. Generally, shallower zones are richer in condensate than deeper zones. For wells connected to gas processing plants and undrilled locations on leases with wells connected to plants, NGLs are projected based on NGL yields obtained from processing plant reports or sales records provided by NFR. Where NGLs are projected, net residue gas sales are reported herein as gas reserves. Where no NGLs are projected, wellhead gas volumes are reported herein as gas reserves. For the table on the first page of this report, MLL consolidated oil and condensate into oil reserves and reported NGL reserves separately.

Some identified development locations are uneconomic based on MLL estimates and SEC-compliant prices and are not included herein. For purposes of this report, projections with positive future net revenues were considered economic even if discounted future net revenues were negative. Many of NFR’s projected Haynesville development wells have positive undiscounted future net revenues but negative discounted future net revenues due to current SEC-compliant gas prices.

Rockies Division

The NFR properties from the Klabzuba acquisition are located in the Bearpaw Arch in north-central Montana. Production is primarily dry gas from shallow clastic reservoir targets including Judith River, Eagle Sandstone, Medicine Hat, Niobrara, and Sawtooth at depths less than 3,000 feet. Current production and future development is based primarily on 160-acre spacing although some reservoirs are being developed on 80-acre spacing.

The NFR properties from the Gasco acquisition are located in the Riverbend Field of Utah. Production is primarily gas with modest condensate yields. From one to six reservoirs are productive at various locations across the field.

Reserves for existing wells were based on extrapolation of production performance, generally using hyperbolic decline curves to a minimum exponential decline rate of six percent per year. Reserves for undeveloped locations are based on analogy, considering the performance of existing wells in the subject area and reservoir.

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Economic Considerations

Future prices and costs were projected based on information provided by NFR. No future escalation of prices or costs was assumed. Operating costs, price differentials from selected benchmarks, and Btu and shrinkage adjustments were included for each well or lease, based on recent actual averages. Operating expenses included both a component cost per well month and a component cost per Mcf produced. Ad valorem and severance taxes were projected based on recent averages, legislated rates, or adjustments used for high cost gas wells in Texas. Capital costs for drilling and completion of future wells and recompletion of existing wells were based on NFR’s recent actual experience and estimates.

Product prices were projected using selected spot price benchmarks (West Texas Intermediate crude oil sold at Cushing, Oklahoma and gas sold at the Henry Hub) with appropriate differentials applied for each well, lease, or area. The SEC prices applicable for year-end 2011 reserves disclosures are calculated for each product as the average of the prices existent on the first day of each month in 2011. For our cash flow projections, constant prices were used throughout the life of production in accordance with SEC guidelines. The SEC-compliant benchmark prices used herein were $96.19 per barrel for oil and $4.118 per million Btu for gas. MLL assumed an NGL price equal to 60 percent of the benchmark oil price. The actual average prices used in this report for proved reserves, after appropriate adjustments, were $90.14 per barrel for oil, $51.79 per barrel for NGLs, and $4.14 per Mcf for gas.

Attachments

Attached Exhibits 1 through 4 are summary totals by reserves category showing annual projections of reserves and cash flows. Exhibit 5 is a one-line summary showing reserves and future cash flows for each of our evaluation cases, grouped by reserves category and sorted alphabetically by entity name within each category. Exhibit 6 is a one-line summary grouped by acquisition (designated by NFR) then sorted by reserves category and entity name. Exhibit 7 is a one-line summary sorted alphabetically by entity name, without reserves category or acquisition groupings. Exhibit 8 is a one-line summary ranking of entities (from highest to lowest discounted future net revenues) within each reserves category. On all the one-line summaries, the East Texas Division properties and the Rockies Division properties are grouped separately.

An index is provided at the beginning of the Exhibits section.

Other Considerations

The timing of production start from development drilling and from recompletions was based on estimates or schedules provided by NFR. Capital costs for development well drilling were generally incorporated into our cash flows from one to five months before production start, based on recent experience with new wells in various areas and reservoirs. Costs for recompletion workovers were

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generally incorporated one month before production start, and completion costs for all wells were generally incorporated just before production start.

Future costs of abandoning facilities and wells and any future costs of restoration of producing fields to satisfy environmental standards were not deducted from total revenues as such estimates are considered separately from our reserves report in NFR’s financial accounting.

Gas volumes are reported at the standard pressure base used for each state. Therefore, some aggregates shown herein are at a mixed pressure base.

Well counts, as reported in the various economic output tables, actually represent completions and recompletions. Thus, a single well bore may be counted more than once in the total well count.

In conducting this evaluation, MLL relied upon production histories; accounting and cost data; ownership; geological, geophysical, and engineering data; development plans supplied by NFR; and upon non-confidential data from public records or commercial data services. These data were accepted as represented and are considered appropriate for the purpose served by the report. MLL used all methods, procedures, and assumptions as it considered necessary and appropriate under the circumstances in using the data provided to prepare the report.

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our 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, (1) the utilization of analogous or indirect data and (2) the application of professional judgments. Government policies and market conditions different from those employed in this study may cause (1) the total quantity of hydrocarbons to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. At this time, MLL is not aware of any regulations that would affect NFR’s ability to recover the estimated reserves and resources.

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 NFR Energy LLC, or any affiliate. Our 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

NFR Energy LLC	January 18, 2012
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By	/s/ Leslie A. Fallon, P.E.
	Leslie A. Fallon, P.E.
	Vice President
By	/s/ Carl D. Richard, P.E.
	Carl D. Richard, P.E.
	Senior Vice President

CDR/psh