CPE-EX99.1-2011.12.31

Pursuant to your request, we have estimated oil, condensate, and natural gas reserves and projected revenues for all properties owned by Callon Petroleum Company. The properties are located in Louisiana, Texas, and in the federal waters of the Gulf of Mexico.



	Net to Callon Petroleum Company*
	Proved Developed			Proved		Total
Constant Product Prices	Producing	Nonproducing		Undeveloped		Proved

Estimated Future Net Oil/Cond., Mbbl	3,078.8	1,990.7		5/5/2008		10,075.2
Estimated Future Net (Sales) Gas, MMcf	9,816.9	1,788.2		23,513.1		35,118.2

Estimated Future Gross Revenue, $M	358,728.9	216,828.6		618,521.7		1,194,079.1
Estimated Future Operating Expenses, $M	197,668.8	36,771.8		47,538.1		281,978.6
Estimated Future Production Taxes, $M	13,313.5	2,935.2		28,945.7		45,194.3
Estimated Future Capital Costs, $M	11,975.8	28,817.3		257,315.2		298,108.3
Estimated Future Net Revenue (“FNR”), $M	135,770.8	148,304.4		284,722.7		568,797.9
Estimated FNR Discounted at 10%, $M	138,524.8	80,899.5		90,466.1		309,890.5

Projected Revenues by Year - Constant Product Prices, $M**
2012	71,571.4	(4,044.2	)	(24,942.0	)	42,585.2
2013	43,877.5	12,105.4		(42,402.8	)	13,580.1
2014	19,271.9	13,265.0		(279.3	)	32,257.5
Thereafter	1,050.0	126,978.2		352,346.8		480,375.1
Total	135,770.8	148,304.4		284,722.7		568,797.9

Estimated 2012 Production
Oil/Cond., Mbbl	766.7	83.8		69.2		919.6
Gas (Sales), MMcf	3,786.7	122.5		130.2		4,039.4

Purpose of Report - The purpose of this report is to provide the management of Callon with a projection of future reserves and revenues for an assessment of oil and gas properties owned by Callon for inclusion in their public filings. The Proved reserve and revenue projections shown herein have been prepared in accordance with Securities and Exchange Commission (“SEC”) requirements for reporting purposes as described below. Although we have prepared projections of Probable reserves, it is our understanding that Callon has elected to exclude such reserve volumes for public reporting purposes.

Reporting Requirements - SEC Regulation S‑K, Item 102, and Regulation S‑X, Rule 4‑10, require oil and gas reserve information to be reported by publicly held companies as supplemental financial data. These regulations were revised by the SEC effective for filings beginning January 1, 2010. The revised regulations provide for certain changes in Proved reserve definitions, add definitions for Probable and Possible reserves, and require that revenues associated with Proved reserves be reported on the basis of the average of the preceding 12‑month, first-of-month product prices. Revenues are to be discounted at 10%, consistent with that required in prior years.

Standards of Practice - This report has been prepared in accordance with our understanding of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information as promulgated by the Society of Petroleum Engineers and the Guidelines for Application of the Definitions for Oil and Gas Reserves prepared by the Society of Petroleum Evaluation Engineers. However, the projected reserves have been prepared with consideration for reserve classification definitions specified by the SEC that do not necessarily conform to definitions promulgated by the Society

Economic Limits - In some cases the projections have been prepared with consideration for overall field production, resulting in negative cash flow projections for certain properties. In our opinion, the projections shown herein properly reflect the expected operations. The projections include consideration for abandonment costs, resulting in negative future revenues and discounted revenues.

Cash Flow Presentation - The gross and net reserve volume columns in the cash flow projections have been separated into three different columns: oil (Mbbl), produced gas (MMcf), and sales gas (MMcf). Product prices, net revenues before taxes, and severance taxes are shown separately for each product.

Extrapolation of performance history and material balance estimates were utilized for projecting future recoverable reserves for the producing properties where sufficient history was available to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production.

Approximately 45% of the future net revenues discounted at 10% are included in the Proved Developed Producing category. The remaining 55% of discounted net revenues are included in the Nonproducing and Undeveloped classifications. Reserve estimates for those properties in the Nonproducing and Undeveloped categories will be subject to a significantly greater level of variation than estimates for producing properties exhibiting established decline trends.

In our opinion the assumptions, methodologies and analytical procedures used in this report are appropriate for SEC reporting purposes. We have used the methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.

Gas Volumes - Gas volumes are reported at the prevailing pressure base of the state in which the reserves are located and at 60 degrees Fahrenheit. The projections reflect gas streams for production gas and sales gas. The difference between the two is intended to reflect fuel and lease usage.

Mississippi Canyon 538/582 - The Medusa Prospect, drilled by Murphy on Mississippi Canyon Blocks 538 and 582 during 1999 and more fully delineated as a result of drilling conducted in 2000 and 2001, successfully tested a number of horizons in two separate fault blocks. Drilling operations conducted during 2002 resulted in certain minor revisions in geological interpretations and reserves were adjusted to reflect a revised study of geological and petrophysical characteristics. Reserve estimates for a total of 17 reservoirs, representing 11 horizons, have been based on volumetric calculations utilizing 3‑D seismic data and subsurface control for mapping, as well as petrophysical calculations derived from well logs and sidewall cores.

Production operations for this property were initiated in November 2003 and there were 8 wellbores producing at the time of report preparation. The estimated reserves for those reservoirs completed in the existing wells have been revised from our original projections to reflect the performance of the wells to date. In some cases Nonproducing and Undeveloped reserve assignments have been adjusted to conform with the performance of the existing completions. On an overall basis the estimated ultimate oil reserves have been increased 3.4% and gas reserves have been decreased 0.6% in comparison to our previous report. The Medusa Prospect represents 37.8% and 7.7% of the oil and gas, respectively, net to Callon.

Garden Banks 341 - The Habanero Prospect drilled by Shell during the first half of 1999 encountered two productive horizons: the Habanero 52 oil sand and the Habanero 55 gas sand. The productive horizons were also tested in a downdip, nonproductive sidetrack that allows for the calculation of hydrocarbon limits in both horizons. Proved reserves were assigned on the basis of information derived from the two wellbores and supported by seismic interpretations. Additional drilling activities conducted during 2001 resulted in establishing the updip productive limits in both reservoirs.

After being sidetracked to its current location in May 2003, production operations were initiated during November 2003 with the No. 2 well being completed in the Habanero 52 sand at a rate of 12,000 BOPD and 19 MMcf/day. In addition, the No. 1 was tested at a rate of 4,700 BOPD and 8.3 MMcf/day; however, the sliding sleeve separating the Habanero 52 and 55 sands was found to be in the open position resulting in the co-mingling of the two zones. A subsequent workover in the No. 1 wellbore resulted in a single completion in the Habanero 52 sand. We have been informed that the Habanero 55 sand is no longer mechanically able to be produced in the No. 1 well and the reserves for this horizon have been eliminated from our report.

The estimated reserves shown herein include consideration for two producing completions in the Habanero 52 oil sand, and one sidetrack location to produce the Habanero 52 gas sand. In comparison to our prior report, projected ultimate oil recoveries have been increased 4.9% and gas recoveries have been revised upward 3.3% to reflect well performance.

The undeveloped reserves for this property have been included in our projected reserves since 2001 and currently are scheduled to be developed upon depletion of the existing completion in the No. 2 wellbore in 2012. We have been informed that it is the intention of the operator to sidetrack the existing wellbore to exploit these reserves. The timing of such operations is the result of physical facilities limitations and economic considerations with respect to both drilling operations for new wellbores and reconfiguration of the facilities.

On an overall basis the estimated reserves attributable to the Habanero Prospect represent 6.0% of the estimated Proved net oil and 13.0% of the Proved net gas for Callon. Approximately 71% of the oil reserves and 94% of the gas reserves for this property have been included in the Undeveloped category.

Wolfberry Properties - In 2009 Callon acquired ownership in four West Texas fields: Block 5, Carpe Diem, East Bloxom, and Kayleigh, located in Crockett, Midland, Upton, and Ector Counties, respectively. The subject properties are located within the Wolfberry trend. During 2011, the Pecan Acres Tract was acquired and two wells were drilled, but not completed. All reserves for this property have been included in the undeveloped category and reserves have been assigned on the basis of offset production. On an overall basis the properties include 69 producing wells, 14 nonproducing wells and recompletions, and 100 undeveloped locations.

Reserve assignments for the producing completions were assigned on the basis of the extrapolation of performance data. Analogy was considered in determining hyperbolic exponents for the estimation of future reserves for those completions that did not have sufficient production history to definitively project the proper decline profile. Reserves for the undeveloped locations were projected on the basis of analogy to existing completions. In all cases, the undeveloped locations are direct offsets to existing completions.

In aggregate, these properties represent 55.9% and 33.6% of oil and gas reserves, respectively, net to Callon. Approximately 64% of the estimated reserves, on an equivalent barrel basis, are in the Undeveloped category. Development operations conducted by Callon during 2011 resulted in 36 wells being drilled (24 producing and 12 awaiting completion).

Swan Lake - During 2010 Callon drilled the Mills No. 1, a Haynesville completion located in Bossier Parish, Louisiana, which had produced approximately 2.15 Bcf by year end 2011. A total of 3 development wells were assigned on the basis of the performance of the subject completion and wells producing in offset sections.

West Cameron Block 295 - West Cameron Block 295, discovered in 2005, is defined by two separate gas accumulations that are productive from similar geologic intervals. However, there is some evidence that the M-1 sands in the two existing wells have some degree of pressure communication though produced fluids vary somewhat in composition. The No. A‑1 (formerly No. 2) wellbore encountered productive sands in the Rob M‑1 horizon (15,370' MD) and the Rob L horizon (13,100' MD). The well was completed in the Rob M‑1 and is currently on production. A development well, designed to effectively drain the M‑1 reservoir (No. A‑2), was drilled during 2006 and encountered the target horizon. The initial completion in the Rob M-1 Lower depleted during 2007 and the well has been recompleted to the Rob M-1.

Reserve estimates for the property were increased to reflect the performance of the existing completions. Ultimate gross recovery for the field is estimated to be approximately 39.7 Bcf. The property represents 3.6% of remaining gas reserves net to Callon.

As we understand the SEC requirements issued on January 14, 2009, oil and gas prices utilized to determine the Standardized Measure of discounted cash flows should be based on the trailing twelve-month average of the first-of-the-month prices. The estimated revenues shown herein reflect the actual average of first-of-the-month prices received by Callon on a property by property basis which conform with benchmark prices of $96.19 per barrel and $4.12 per MMBtu. All prices were held constant over the producing life of the properties. The projected prices for both oil and gas were based on our understanding of SEC requirements.

Gas prices have been adjusted to reflect the Btu content, transportation charges, and other fees specific to the individual properties. Gas prices for certain properties (most notably in West Texas) include consideration for processing arrangements and the price shown herein has been adjusted to reflect such arrangements in comparison to produced gas volumes. On an overall basis, the wellhead gas prices utilized herein are approximately 10% greater than the values utilized as of December 31, 2010. Market level gas prices are subject to a significant level of variation depending on location and marketing considerations specific to the individual properties. In our opinion, it is likely that there will be a substantial degree of variation in prices in the future. Spot prices for natural gas have experienced a large degree of volatility during recent years, which can be attributed to seasonal demands and other market considerations.

The projected oil prices for individual properties have been adjusted to reflect all wellhead deductions and premiums on a property by property basis, including transportation costs, location differentials, and crude quality. The weighted average wellhead prices shown herein are approximately 27% greater than those utilized for our report prepared as of December 31, 2010, which has had a material impact on estimated future revenues and in some cases has marginally affected economically recoverable reserves. Variations in oil prices are the result of changes in market conditions and future prices are likely to be affected by a variety of factors including OPEC actions, political and market considerations, and overall economic conditions.

Operating expenses, generally shown as dollars per well per month for onshore properties, were provided by Callon and adjusted for nonrecurring costs where applicable. Operating costs for the Wolfberry properties include a component of variable costs projected on a unit of production basis to reflect declining expenses associated with decreasing

producing levels. In some cases, particularly for the offshore properties, operating costs were projected on a total-unit or platform basis and the projections were continued until the unit or facility reached the economic limit. Severance and ad valorem taxes were calculated at the rates applicable to each property and have been deducted from the cash flow. Operating costs were held constant over the economic life of the properties.

Capital costs necessary to perform recompletions and to drill new wells were supplied by Callon. We have generally reviewed the projected expenditures and they are consistent with our perception of current costs necessary to perform the intended operations. Capital costs were held constant over the life of the properties.

Abandonment costs for all properties were included in the projections where Callon has determined the total cost associated with abandoning the facilities and platforms will exceed salvage value. In some cases, funds have been escrowed to cover anticipated future abandonment costs. The projections reflect a total of $29,442,406 in abandonment costs.

Additional Potential Values - Values were not assigned to nonproducing acreage or to acreage held by production, if any. In general, the salvage of surface and subsurface equipment for the onshore properties was assumed to be equal to abandonment costs.

Development - Callon has assured us of its intent and ability to proceed with the development activities included in this report and that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter these plans.

Data Sources - Essentially all data were furnished by Callon, including production statistics, product prices, operating costs, ownership, and basic well information. In some cases we have considered information from our files or data from publically available sources. We have accepted the data as represented. We express no opinions and make no representations as to legal or accounting interpretations provided by Callon. Production statistics for the significant Callon-operated properties and for several of the other more significant properties were available through December 2011.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. If the reserves are recovered, the resulting revenues and the related costs could be more or less than the estimated amounts. As a result of governmental regulations and policies and uncertainties in supply and demand, the sales rates, the prices received for produced reserves, the ability to recover the reserves, and the costs incurred in recovering such reserves may vary from the assumptions made in the preparation of this report. Estimates of reserves may increase or decrease as a result of future operations, market conditions, and/or changes in governmental regulations or policies.



	2011	Maximum	Average over Live

Oil, $/bbl	100.74	101.2	98.98
Gas, $/Mcf	5.00	6.03	5.60