Document:

March 10, 2011

Greg
Franklin

Osage Energy Corporation

100 Park Avenue, Suite 1040

Oklahoma City, OK 73102

 

Dear
Mr. Franklin:

As
requested we have prepared an economic and reserve appraisal report of Proved Developed Producing (PDP-Water Flood) & Proved
Behind Pipe (BP) reserves to the interests of Osage Energy Corporation in Hopper-Osage Lease (Twin Creek Field), Osage
County, Oklahoma. A summary based on Unescalatcd pricing case effective December 31, 2010 is as follows:

 

	EFFECTIVE
    DATE	RESERVE
    TYPE	NETBBLS	NET'
    MCF	FUTURE
    NET REVENUE ($)	DISCOUNTED
    FNR($)@10%
	12/31/2010	Proved
    producing (PDP)	59,514	-0-	3,318.40	2,261,054
	(Water
    Hood)
	12/31/2010	Proved
    Behind Pipe (BP)	66,929	200,771	5,134,166	3,921,406
	TOTAL	 	126,443	200,771	8,452,563	6,182,460

 

EVALUATION
METHODOLOGY

GENERAL:

Detailed
results of our evaluation for new wells is presented in the form of a summary report with One Line Well Information showing Gross/Net
Oil & Gas Production, Future Cash Flow, Lease Operating Expenses, Production taxes, Discounted Cash Flow at 10%. Individual
lease/well economic sheets provide detail economics, remaining reserves, production curves and also the location of the lease/well
and other pertinent data.

This
report has been prepared on a Before Income Tax basis and does not give consideration to salvage value, depletion or taxes other
than those specifically mentioned. Also no encumbrances against or debits owed on the properties have been considered. All ownership
interests, Lease Operating Expenses and product pricing have been furnished by Osage Energy Corporation.

 

    	1

    	 

    
 

OSAGE ENERGY CORPORATION

 

RESERVES AND APPRAISAL REPORT

OF

PRODUCING PROPERTIES

&

BEHIND PIPE RESERVES

IN

OKLAHOMA

 

EFFECTIVE DATE 12-31-2010

 

    	2

    	 

    
 

ENGINEERING:

Oil
and gas reserves were estimated by use of production performance curves and material balance calculations where applicable. If
insufficient production history available to evaluate by curves, estimates were made by using analogous, nearby producing reservoirs,
and/or volumetric calculations. Verbal production information provided by Osage Energy Corporation is used in the evaluation.
Perforated interval and proposed BP zone interval is marked on the logs where available and log calculations were made. Drainage
areas were estimated based on the well density in the sections where wells arc completed. BTTP data is gathered from offset wells
producing from similar reservoir. For all the Behind Reserves, we have assumed a production start date and estimated work over
costs. Reserves estimated in this report are very subjective and should be revised up/down based on all the information including
any production history after completion. All methods used to project reserves are industry accepted petroleum reservoir evaluation
methods.

OIL,
CAS PRICING AND LEASE OPERATING EXPENSES:

An
Oil Price of $80.00/BBL, Gas Price of $3.50/MCF and current Lease Operating Expenses arc used in this report. Prices and Lease
Operating Expenses are not escalated.

Every
effort was made to forecast the best possible estimate of future producible oil and gas reserves. However, the accuracy of any
reserve estimate is a function of the quality of available data and of judgment. While reserve estimates presented in this report
are believed to be reasonable, they should be accepted with the understanding that future operations or subsequent reservoir performance
or more accurate data received subsequent to the preparation of this report may justify a revision of these estimates either upward
or downward.

All
descriptions, information and other materials ("DATA") included in this report are solely for convenience purposes and
any reliance on or use of such data is at your own risk and you should conduct your own due diligence. The Reddy Petroleum Company
and its associates make no warranties or representations, express or implied, as to the accuracy or correctness of data presented
in this report or to the quality or quantity of the hydrocarbon reserves attributed to the Behind Pipe and Incremental Reserves,
or the ability of any property to produce hydrocarbons.

We
appreciate the opportunity of preparing this evaluation and, if you have any questions or necd additional information, please
advice.

Respectfully
submitted,

REDDY
PETROLEUM COMPANY

 

	By:	/s/ Raja P. Reddy	 
	 	Raja P. Reddy	 
	 	Petroleum Consultant	 
	 	Petroleum Engineer	 

    	3

    	 

    

 

    	4Exhibit 10.25

	II 		Evaluation of the Guaduas
Field in Middle/Upper Magdalena Valley 

The
Guaduas field is located in the Dindal and Rio Seco Blocks. It covers 30,665 acres in the Middle Magdalena Valley and is approximately
62 miles northwest of the City of Bogota. The Company purchased 90.6% working interest in this property from SiPetrol S.A. on
July 6, 2006 and became the operator. The remaining 9.4% working interest belongs to Cimarrona Oil & Gas. The oil and gas
production are subject to a 20% royalty rate.

Geology.
Discovery, and Production of the Guaduas Field

The
Guaduas field is located in the Middle Magdalena Valley Basin on the west flank of the Guaduas syncline and is a hanging-wall
anticlinal feature created by the movement of the Honda thrust. The Guaduas field was discovered in 1996 by GHK Company, LLC of
Oklahoma from the drilling of the El Segundo-IE well and was placed on production later that year through an extended production
test. Production is from the late Cretaceous Cimarrona formation, which is a sequence of alternating clastic and carbonate rocks
deposited in a transitional marine environment. The Cimarrona formation in the uaduas field is composed of fractured limestone
and calcareous sandstone, interbedded with calcareous shale and siltstones.

The
Guaduas closure to the north, south and west is structural in nature, while the eastern closure is based on a facies change. The
deposit environment is marine to transitional. In the area of the Guaduas field, wells encountered Cimarrona thickness between
230 and 350 feet. During exploration, it was discovered that hydrocarbon accumulations are controlled by the presence of fractures
and limited almost exclusively to the fractures. Development focused on fracturing and evelopment of limestone and sands, drilling
perpendicularly to the direction of the fractures in order to drain most of the hydrocarbons found in the fractures.

Full
field development began in 2001 with production peaking in 2002 prior to declining to present day levels. In the early stages
of exploration, the Cimarrona formation was identified as a clastic sequence that varied in lithology, from onglomerate sediments
related to deltaic fans, canals and marine bars from coastal environments, to shallow-water limestone. Later exploration efforts
resulted in the discovery that hydrocarbon accumulations in the area were controlled by the presence of fractures and limited
almost exclusively to the fractures, with minimal matrix contribution. Development therefore focused on fracturing and the development
of limestone and sandstone by drilling perpendicularly to the direction of the fractures in order to drain the highest percentage
of hydrocarbons found in these fracture systems.

As
of year-end 2010, 17 wells have been drilled with seven producing oil wells and eight non-producing oil wells, one water injection
well and one gas injection well. For the purposes of this evaluation, all seven oil wells are producing and two non-producing
oil wells were scheduled for workovers in 2010 but no work was done. The daily average rate for 2010 was 641 barrels of 19°API
crude, 4,270 Mcf of gas and 1,076 barrels of water for the 2010 production of 234,133 barrels of oil, 1,558,595 Mcf of gas and
392,737 barrels of water. Cumulative production to December 31, 2010 was 10,990,993 barrels of oil, 22,930,983 Mcf of gas and
4,269,587 barrels of water. Wells produce through a combination of electrical submersible pumps (ESP), progressive cavity pumps
(PCP) and gas lift. Produced gas is used for fuel, re-injected for pressure maintenance and gas sales. Produced water is re-injected
for disposal. A review of gas-oil ratio performance indicates that gas breakthrough has occurred in a number of producing wells.

    	1

    	 

    
The
discovery well, the El Segundo IE well, was located using the seismic database existing in 1996 that consisted only of 2-D seismic.
The 2-D seismic outlining the field consists of 14 seismic profiles with separations between transversal lines of approximately
three km and six km between the direction lines. The reprocessing resulted in an improvement in the frequency content, image reproduction
and seismic character. There is a total of 254 km of 2-D seismic available for the area.

In
view of the exploratory success with additional wells, 129 km2 of 3-D seismic was acquired. Additional reprocessing
was performed on the 3-D seismic to eliminate static problems and to improve definition of seismic events of the Cimarrona Formation,
to better define the faults and to visualize the reservoir's area. The 3-D seismic was used to improve mapping of the structure,
defining orientation of principal faults and pin-pointing the reservoirs position, allowing for better planning of development
wells. As part of an integrated reservoir study, in conjunction with the seismic reprocessing, synthetic seismograms were built
relating to the area wells to improve structural interpretation of the reservoir

Reservoir
Evaluation

Within
the Cimarrona formation, the porosity ranges from 0 to 5% with permeability ranges from 0.01 to 1 mD. The oil is trapped in fractures.
Based on petrophysical properties combined with a stratigraphic model, the Cimarrona formation is divided into the Upper Cimarrona
(Flow units FU1, FU2, FU3,FU4 and FU5) and Lower Cimarrona (Flow units FU6, FU7 and FU8). The FU2 is the principal reservoir
and FU4 and FU5 are considered good reservoirs

Work
Program

Through
infill drilling the Company plans to continue development of the field in order to maintain production decline rates as existing
wells are abandoned. One highly delineated well is planned for 2010. If successful, another development well will be drilled in
2011 (see Figure II-3). Two more similar wells are planned for 2012 depending on the results of the 2010 infill drilling.

    	2

    	 

    
Figure
II-1 Location Map of the Guaduas Field in the Middle Magdalena Valley,Colombia

 

    	3

    	 

    

Figure
II-2 Stratigraphic Chart of the Middle Magdalena Valley 

 

 

 

    	4

    	 

    

Figure
II-3 Guaduas Field Delineated Well Development Locations

 

 

    	5

    	 

    

Capital
Costs

 

The total capital expenditures for the drilling of four additional wells are as follows:

 

	Description 	Cost (in U.S. M$)
	ES_2S
    workover to fix mechanical problem in 2011	300.0	 
	Drill
    and complete 1 deviated well in 2011	5,500.0	 
	Facility,
    location, tie-in and environmental study for 1 well in 2011	500.0	 
	Drill
    and complete 1 vertical well in 2012	3,000.0	 
	Facility,
    location, tie-in and environmental study for 1 well in 2012	500.0	 
	Drill
    and complete 2 deviated (1 vert. + 1 horiz.) wells in 2012	8,500.0	 
	Facility,
    location, tie-in and environmental study for 2 wells in 2012	1,000.0	 
	Total
    Costs	19,300.0	 

The
Company's share of field development costs at 90.6% working interest is equal to $17,485,800. The following is a detailed timeline
for abandonment of Guaduas wells:

 

	Well
    Name	Date	Well
    Name	Date	Well
    Name	Date
	TP
    7W	2011	ES_1S	2021	Development
    Well #1	2019
	TP
    IE	2019	TP_6E_ST2	2016	Development
    Well #2	2016
	ES
    2S	2018	ES_2E_ST1	2015	Development
    Well #3	2021
	TP
    6N	2012	ES_5N	2021	Development
    Well #4	2016

Operating
Costs

The
total 2010 operating expenses (excluding transportation) totaled $4,198,399 (100% working interest). The fixed cost was 95% of
the total operating cost, resulting in $336,671 per month for the Guaduas oil field. The variable cost is 5% of the total operating
cost and, based on 212,124 barrels of total oil production, the resulting cost was $4.09 per barrel. The transportation cost was
$1.50 per barrel.

 

	Economic Assumptions and Parameters	 
	Working
    Interest	90.6%
	Royalty
    Rate	20%
	WTI
    Oil Price on December 31, 2010	US$91.40
    per barrel
	Vasconia
    Price on December 31, 2010	US$90.80
    per barrel
	Guaduas
    Oil Price 2010	US$89.16
    per barrel
	Forecast
    Oil Price	Escalate
    at NYMEX futures for WTI light crude
	Escalation
    factor for costs	4%
    per year based on Colombia consumer index
	Contract
    Expiration	February
    2021
	Operating
    Days	estimated
    at 365 per year
	Abandonment,
    salvage, clean-up	$100,000/well

    	6

    	 

    

Reserve

Proved
developed producing reserves have been assigned to seven Guaduas wells based on the 
production performance trends of the historical data. The  following table outlines the proved developed
producing reserves estimates:

 

	 	 	 	 	 	 	 	 	 	 	 	Estimated	 	 	 	 	 	 	 	Remaining to	 	 	 	Remaining to	 
	 	 	 	 	 	 	 	Cumulative	 	 	 	Ultimate	 	 	 	Remaining	 	 	 	Contract	 	 	 	Economic	 
	 	 	 	 	 	 	 	Production	 	 	 	Recoverable	 	 	 	Recoverable	 	 	 	Expiry	 	 	 	Limit	 
	Well Name	 	 	Category	 	 	 	(bbl)	 	 	 	(bbl)	 	 	 	(bbl)	 	 	 	(bbl)	 	 	 	(bbl)	 
	ES_1S	 	 	PDP	 	 	 	2,655,246	 	 	 	3,555,567	 	 	 	900,321	 	 	 	603,285	 	 	 	720,996	 
	ES_2E_ST1	 	 	PDP	 	 	 	866,099	 	 	 	1,006,020	 	 	 	139,921	 	 	 	72,542	 	 	 	72,542	 
	ES_5N	 	 	PDP	 	 	 	870,304	 	 	 	1,709,067	 	 	 	838,763	 	 	 	394,942	 	 	 	614,427	 
	TP_1E	 	 	PDP	 	 	 	1,700,124	 	 	 	1,937,036	 	 	 	236,912	 	 	 	143,338	 	 	 	143,338	 
	TP_6E_ST2	 	 	PUP	 	 	 	424,047	 	 	 	582,847	 	 	 	158,800	 	 	 	76,025	 	 	 	76.025	 
	TP_6N	 	 	PDP	 	 	 	677,368	 	 	 	705,958	 	 	 	28,590	 	 	 	8,673	 	 	 	8,673	 
	7P_7W	 	 	PDP	 	 	 	352,019	 	 	 	361,961	 	 	 	9,942	 	 	 	—  	 	 	 	—  	 
	Total	 	 	 	 	 	 	7,545,207	 	 	 	9,858,456	 	 	 	2,313,249	 	 	 	1,298,805	 	 	 	1,636,001	 

(1)        
Production decline analysis found in Appendix B

(2)         
Cumulative production to December 31, 2010.

(3)         
Estimate ultimate recoverable based on 5 bopd cutoff.

Based
on surrounding production analogues and 3-D seismic interpretations, proved undeveloped reserve are assigned to two delineated
infill wells (Development Well #1 & Development Well #2) in the
 Guaduas field (see Figure II-3).

 

	 	 	 	 	 	 	 	 	 	 	 	Estimated	 	 	 	 	 	 	 	Remaining to	 	 	 	Remaining to	 
	 	 	 	 	 	 	 	Cumulative	 	 	 	Ultimate	 	 	 	Remaining	 	 	 	Contract	 	 	 	Economic	 
	 	 	 	 	 	 	 	Production	 	 	 	Recoverable	 	 	 	Recoverable	 	 	 	Expiry	 	 	 	Limit	 
	Well Name	 	 	Category	 	 	 	(bbl)	 	 	 	(bbl)	 	 	 	(bbl)	 	 	 	(bbl)	 	 	 	(bbl)	 
	Development Well #1	 	 	PUD	 	 	 	—  	 	 	 	1,689,233	 	 	 	1,689,233	 	 	 	1,020,346	 	 	 	1,020,346	 
	Development Well #2	 	 	PUD	 	 	 	—  	 	 	 	262,377	 	 	 	262,377	 	 	 	149,259	 	 	 	149,259	 
	Total	 	 	 	 	 	 	—  	 	 	 	1,951,610	 	 	 	1,951,610	 	 	 	1,169,605	 	 	 	1,169,605	 

(1)         
Analogue models found later in this section.

(2)         
Estimate ultimate recoverable based on 15 bopd cutoff

(3)         
Development Well #2 to be drilled in pressure depleted reservoir therefore lower recovery

 

	 	 	 	 	 	 	 	 	 	 	 	Estimated	 	 	 	 	 	 	Remaining to 	 	 	 	Remaining to	 
	 	 	 	 	 	 	 	Cumulative	 	 	 	Ultimate	 	 	 	Remaining	 	 	Contract	 	 	 	Economic	 
	 	 	 	 	 	 	 	Production	 	 	 	Recoverable	 	 	 	Recoverable	 	 	 Expiry	 	 	 	Limit	 
	Well Name	 	 	Category	 	 	 	(bbl)	 	 	 	(bbl)	 	 	 	(bbl)	 	 	(bbl)	 	 	 	(bbl)	 
	ES_IN	 	 	PDNP	 	 	 	300,985	 	 	 	572,808	 	 	 	271,823	 	 	176,154	 	 	 	176,154	 
	ES_2S	 	 	PDNP	 	 	 	175,191	 	 	 	844,631	 	 	 	669,440	 	 	146,791	 	 	 	146,791	 
	ES_6E_ST2	 	 	PDNP	 	 	 	103,862	 	 	 	263,642	 	 	 	159,780	 	 	102,713	 	 	 	102,713	 
	Total	 	 	 	 	 	 	580,038	 	 	 	1,681,081	 	 	 	1,101,043	 	 	425,658	 	 	 	425,658	 

(1)
The ES_2S reserve is based on the well coming back at the same rate it was shut-in August 2008 (see Production Forecast and Methods
section).

    	7

    	 

    
Based
on surrounding production analogs and 3-D seismic interpretations, probable undeveloped reserve is assigned to two delineated
infill wells (Development Well #3 &Development Well #4) in the Guaduas field. These infill locations will offset the Development
#1 and #2 wells depending on results.

	 	 	 	 	 	 	 	 	 	 	 	Estimated	 	 	 	 	 	 	 	Remaining to	 	 	 	Remaining to	 
	 	 	 	 	 	 	 	Cumulative	 	 	 	Ultimate	 	 	 	Remaining	 	 	 	Contract	 	 	 	Economic	 
	 	 	 	 	 	 	 	Production	 	 	 	Recoverable	 	 	 	Recoverable	 	 	 	Expiry	 	 	 	Limit	 
	Well Name	 	 	Category	 	 	 	(bbl)	 	 	 	(bbl)	 	 	 	(bbl)	 	 	 	(bbl)	 	 	 	(bbl)	 
	Development Well #3	 	 	Probable	 	 	 	—  	 	 	 	1,689,233	 	 	 	1,689,233	 	 	 	1,020,129	 	 	 	1,020,129	 
	Development Well #4	 	 	Probable	 	 	 	—  	 	 	 	262,377	 	 	 	262,377	 	 	 	256,677	 	 	 	256,677	 
	Total	 	 	 	 	 	 	—  	 	 	 	1,951,610	 	 	 	1.951,610	 	 	 	1,276,806	 	 	 	1,276506	 

(1)          
Analogue models found later in this section.

(2)          
Estimate ultimate recoverable based on 15 bopd cutoff

(3)          
Development Well #4 to be drilled in pressure depleted reservoir therefore lower recovery

Production
Forecast and Declines

The
proved developed producing forecasts are based on production performance trends.

 

	 	 	PDP
                                                                                                                 Initial	 	 	 	 	 
	 	 	Rate
                                                                                                                                    in 2011	 	 	 	PDP Decline Rate
	Well Name	 	(bopd)	 	 	 	(%/year)	 
	ES_IS	 	284.0	 	 	 	10.4	 
	ES_2E ST1	 	57.7	 	 	 	12.2	 
	ES_5N	 	152.5	 	 	 	6.4	 
	TP_1E	 	68.5	 	 	 	9.1	 
	TP_6E_ST2	 	48.2	 	 	 	9.1	 
	TP_6N	 	27.6	 	 	 	23.4	 
	7P_7W	 	18.1	 	 	 	37.2	 

 

(1)Production
decline analyses are in Appendix B.

The
proved developed non-producing forecast for the ES_2S workover is based on production performance trends of the ES_2S well.

 

	 	 	PDNP Initial	 	 	 	PDNP Decline	 
	 	 	Rate	 	 	 	Rate	 
	Well Name	 	(bopd)	 	 	 	(%/year)	 
	ES_2S	 	95.2	 	 	 	14.0	 

The
proved undeveloped and probable undeveloped forecasts are based on two analog well models. Analog Model #2 (see plot below) is
for a location with initial reservoir pressure and Analog Model #1 (see Figure II-4 and II-5) is for a location within the pressure
depleted reservoir.

	 	 	Initial Rate	 	 	 	Decline Rate	 
	Well Name	 	(bopd)	 	 	 	(%/year)	 
	Analogue Model #1	 	250.0	 	 	 	42.0	 
	Analogue Model #2	 	1,250.0	 	 	 	36.0	 

    	8

    	 

    

		Table
    II-l - Summary of Guaduas Reserve and Net Present Values	 	 
	 	 	Heavy
    Oil Reserves	 	Before
    Tax NPV	 
	 	 	100%	Gross	Net	0%	5%	10%	15%	20%
	Well	Category	(Mbbl)	(Mbbl)	(Mbbl)	(M$)	(M$)	(M$)	(M$)	(M$)
	ES-lS	Proved
    developed producing	603	547	437	30,297	25,240	21.565	18,816	16,703
	ES-2E-ST1	Proved
    developed producing	73	66	53	1,740	1,620	1.518	1,430	1,354
	ES-5N	Proved
    developed producing	395	358	286	17,993	14,760	12,439	10,724	9,422
	TP-1E	Proved
    developed producing	143	130	104	3,606	3,204	2.883	2,623	2,409
	TP-6E-ST2	Proved
    developed producing	76	69	55	1,387	1,292	1,210	1,139	1,076
	TP-6N*	Proved
    developed producing	9	8	6	-25	24	-24	-23	-23
	TP-7W*	Proved
    developed producing	-	-	 	-94	-92	-90	-88	-86
	 	Total
    PDP	1,299	1,177	941	54,904	46,000	39,502	34,620	30,854
	ES-1N	 Proved
    developed non-producing	177	160	128	5,074	4,394	3,875	3,471	3,148
	ES-2S	Proved	147	133	106	4,133	3,731	3,402	3,129	2,899
	ES-6E-ST2	Proved
    developed non-producing	103	93	74	2,960	2,725	2,527	2,359	2,215
	 	Total
    PDNP	427	386	309	12,166	10,850	9,805	8,959	8,263
	PUD-1	Proved
    undeveloped	1,020	924	740	50,312	44,909	40,534	36,937	33,933
	PUD-2	Proved
    undeveloped	155	140	112	3,420	2,943	2,552	2,229	1,960
	 	Total
    PUD	1,175	1,064	852	53,732	47,851	43,087	39,167	35,892
	 	Total
    Proved	2,900	2,628	2,102	120,801	104,701	92,393	82,746	75,009
	ES-lS	Probable
    Producing	426	386	309	25,213	20,791	17,607	15,247	13,447
	 	Total
    Probable Producing	426	386	309	25,213	20,791	17,607	15,247	13,447
	PBUD-1	Probable
    Undeveloped	1.020	924	739	49,247	41,584	35,604	30,851	27,009
	PB
    UD-2	Probable
    Undeveloped	154	140	112	3,100	2,504	2,030	1,649	1,339
	 	Total
    Probable Undeveloped	1,175	1,064	851	52,346	44,088	37,634	32,500	28,348
	 	Total
    Probable	1,601	1,450	1,160	77,559	64,880	55,241	47,747	41,796
	 	Total
    Proved + Probable	4,501	4,078	3,262	198,360	169,581	147,635	130,493	116,805
	 
	
    * Uneconomic wells are included with abandonment costs.
	 

    	9

    	 

    
Table
II-2 Guaduas Field Total Proved Developed Producing Reserve and

Net
Present Values

Working
Interest = 90.6%

Royalty
rate = 20%

Escalation
Factor = 4% per year based on Colombian Consumer Index

Forecast
Oil Price = see Forecast Oil Prices

Fixed
OpEx = $446,000 per well per year fixed cost

Variable
OpEx = $6.30 per barrel

Operating
Days = 365 per year

Abandonment
Cost = $100,000 per well

Effective
Date = December 31, 2010

 

	 	Heavy
    Oil Reserves	 	 	Revenue	 	 	 
	 	 	 	 	 	Gas 	 		Before
	 	 	 	Gross		 (Less	 	 	Tax
	 	 100%
    Gross Net	Royalty	Gas	Oil	 Royalty)	CapEx	OpEx	NPV
	Year	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(M$)	(M$)	(M$)	(M$)	(M$)
	2011	219	198	159	40	43	14,133	111	188	3,924	10,131
	2012	186	168	135	34	36	12,048	105	-	3,422	8,731
	2013	165	150	120	30	32	10,587	98	-	3,431	7,254
	2014	148	134	107	27	29	9,455	90	-	3,460	6,085
	2015	134	121	97	24	26	8,568	84	110	3,504	5,038
	2016	113	102	82	20	22	7,269	73	115	2,956	4,271
	2017	95	86	69	17	18	6,210	62	-	2,377	3,895
	2018	87	79	63	16	17	5,844	58	-	2,417	3,485
	2019	81	73	59	15	16	5,523	55	129	2,464	2,986
	2020	66	59	47	12	13	4,558	46	-	1,802	2,802
	2021	5	5	4	1	1	379	4	-	155	228
	Total	1,299	1,177	941	235	253	84,573	785	542	29,912	54,904

 

	NPV
    of Future Net Revenue
	
    Before Tax Discounted (in M$) @
	0%
    	5%	10%	15%	20%
	54,904	 46,000	39,502	34,620	30,854

 

    	10

    	 

    

Table
II-3 Guaduas Field Proved Developed Non-Producing Reserve and

Net
Present Values

Working
Interest = 90.6%

Royalty
rate = 20%

Escalation
Factor = 4% per year based on Colombian Consumer Index

Forecast
Oil Price = see Forecast Oil Prices

Fixed
OpEx = $446,000 per well per year fixed cost

Variable
OpEx = $6.30 per barrel

Operating
Days = 365 per year

Abandonment
Cost = $100,000 per well

Effective
Date = December 31, 2010

 

	 	Heavy
    Oil Reserves	 	 	Revenue	 	 	 
	 	 	 	 	 	 	 	Gas	 	 	Before
	 	 	 	 	 	Gross	 	(Less	 	 	Tax
	 	100%	Gross	Net	Royally	Gas	Oil	Royalty!	Cap
    Ex	OpEx	NPV
	Year	(Ml.hl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(M$)	(M$)	(M$)	(M$)	(M$)
	2011	84	76	61	15	16	5,428	43	272	1.817	3,381
	2012	71	64	51	13	14	4,597	10	-	1,812	2.824
	2013	60	55	44	11	12	3,869	36	-	1,819	2,086
	2014	52	47	38	9	10	3,321	32	-	1,839	1,513
	2015	45	41	33	8	9	2,900	28	-	1.868	1,060
	2016	40	36	29	7	8	2.572	26	115	1.906	577
	2017	26	24	19	5	5	1.707	17	-	1,317	408
	2018	23	21	17	4	5	1.569	16	124	1,350	110
	2019	12	11	9	2	2	833	8	-	706	135
	2020	11	10	8	2	2	786	8	-	727	68
	2021	1	1	1	0	0	65	1	-	63	3
	Total	427	386	309	77	83	27,647	254	510	15,225	12.166

 

	NPV of Future Net Revenue

Before
Tax Discounted (in M$) @

	0%	5%	10%	15%	20%
	12.166	10.850	9.805	8,959	8,263

    	11

    	 

    

Table
II-4 Guaduas Field Proved Undeveloped Reserve and Net Present Values

Working
Interest = 90.6%

Royalty
rate = 20%

Escalation
Factor = 4% per year based on Colombian Consumer Index

Forecast
Oil Price = see Forecast Oil Prices

Fixed
OpEx = $446,000 per well per year fixed cost

Variable
OpEx = $6.30 per barrel

Operating
Days = 365 per year

Abandonment
Cost = $100,000 per well

Effective
Date = December 31, 2010

 

	 	Heavy
    Oil Reserves	 	 	Revenue	 	 	 
	 	 	 	 	 	 	 	Gas	 	 	Before
	 	 	 	 	 	Gross	 	(Less	 	 	Tax
	 	100%	Gross	Net	Royally	Gas	Oil	Royalty)	Cap
    Ex	OpEx	NPV
	Year	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(M$)	(M$)	(M$)	(M$)	(M$)
	2011	240	217	174	43	47	15.502	122	5,436	1,369	8,818
	2012	347	315	252	63	68	22,526	196	3,298	2,990	16,434
	2013	233	211	169	42	45	14,920	137	 	2,400	12,657
	2014	146	132	106	26	28	9,311	89	-	1,941	7,459
	2015	92	83	67	17	18	5,862	57	-	1,656	4,263
	2016	54	49	39	10	10	3,463	35	115	1,188	2,195
	2017	31	28	22	6	6	2,032	20	-	788	1,264
	2018	20	18	14	4	4	1,327	13	-	736	604
	2019	13	12	9	2	2	866	9	129	710	36
	Total	1,175	1,064	852	213	229	75,809	678	8,977	13,778	53,732

 

	NPV
    of Future Net Revenue
	Before
    Tax Discounted (in M$) @
	0%	5%	10%	15%	20%
	53,732	47,851	43,087	39,167	35,892

    	12

    	 

    

Table
II-5 Cuaduas Field Total Proved Reserve and Net Present Values

Working
Interest = 90.6%

Royalty
rate = 20%

Escalation
Factor = 4% per year based on Colombian Consumer Index

Forecast
Oil Price = see Forecast Oil Prices

Fixed
OpEx = $446,000 per well per year fixed cost

Variable
OpEx = $6.30 per barrel

Operating
Days = 365 per year

Abandonment
Cost = $100,000 per  well

Effective
Date = December 31. 2010

 

	 	Heavy
    Oil Reserves	 	 	Revenue	 	 	 
	 	 	 	 	 	 	 	Gas	 	 	Before
	 	 	 	 	 	Gross	 	(Less	 	 	Tax
	 	100%	Gross	Net	Royalty	Gas	Oil	Royalty)	CapEx	OpEx	NPV
	Year	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MS)	(MS)	(MS)	(MS)	(MS)
	2011	543	492	393	98	106	35,062	276	5,896	7,111	22,331
	2012	604	547	438	109	118	39,171	340	3,298	8,224	27,989
	2013	458	415	332	83	89	29,377	271	-	7,651	21,997
	2014	346	314	251	63	67	22,086	211	-	7,240	15,057
	2015	271	246	197	49	53	17,330	170	110	7,029	10,361
	2016	207	188	150	38	40	13,304	133	344	6,050	7,043
	2017	152	137	110	27	30	9,949	99	-	4,482	5,567
	2018	131	118	95	24	25	8,739	87	124	4,503	4,199
	2019	106	96	77	19	21	7,222	72	258	3,879	3,157
	2020	77	70	56	14	15	5,344	53	-	2,528	2,869
	2021	6	6	5	1	1	444	4	-	218	231
	Total	2,900	2,628	2,102	526	565	188,029	1,716	10,030	58,914	120,801

 

	NPV
    of Future Net Revenue 
	Before
    Tax Discounted (in MS) @   
	0%	5%	10%	15%	20%
	120.801	  104,701	92,393	82,746	75,009

    	13

    	 

    

 

Table
H-6 Guaduas Field Probable Developed Reserve and Net Present Values

Working
Interest = 90.6%

Royalty
rate = 20%

Escalation
Factor = 4% per year based on Colombian Consumer Index

Forecast
Oil Price = see Forecast Oil Prices

CapEx
= $5,500,000 per deviated well and $3,000,000 per vertical well drilling cost

Fixed
OpEx = $446,000 per well per year fixed cost

Variable
OpEx = $6.30 per barrel

Operating
Days = 365 per year

Abandonment
Cost = $100,000 per well

Effective
Date = December 30, 2010

 

	 	Heavy
    Oil Reserves	 	 	Revenue	 	 	 
	 	 	 	 	Gas	 	 	Before
	 	 	 	Gross	(Less	 	 	Tax
	 	100%
         Gross       Net	Royalty	Gas	Oil
            Royalty)	Capi'.x	OpEx	NPV
	Year	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MS)	(M$)	(M$)	(M$)	(MS)
	2011	69	62	50	12	13	4,432	35	-	391	4,076
	2012	60	54	43	11	12	3,886	34	-	356	3,564
	2013	53	48	38	10	10	3.370	31	-	324	3,077
	2014	47	42	34	8	9	2,969	28	-	299	2.698
	2015	42	38	30	8	8	2,653	26	-	277	2,401
	2016	37	34	27	7	7	2,402	24	-	260	2,166
	2017	34	30	24	6	7	2.205	22	-	243	1,984
	2018	31	28	22	6	6	2.041	20	-	229	1.832
	2019	28	25	20	5	5	1.897	19	-	217	1,699
	2020	26	23	18	5	5	1,775	18	-	207	1,586
	2021	2	2	1	0	0	146	1	-	17	130
	Total	426	386	309	77	83	27,775	258	-	2,821	25,213

 

	NPV
    of Future Net Revenue
	Before
    Tax Discounted (in MS) @
	0%	5%	10%	15%	20%
	25.213	20.791	17,607	15,247	13,447

    	14

    	 

    

Table
II-7 Guaduas Field Probable Undeveloped Reserve and Net Present Values

Working
Interest - 90.6%

Royalty
rate = 20%

Escalation
Factor = 4% per year based on Colombian Consumer Index

Forecast
Oil Price = see Forecast Oil Prices

CapEx
= $5,500,000 per deviated well and $3,000,000 per vertical well drilling cost

Fixed
OpEx = $446,000 per well per year fixed cost

Variable
OpEx = $6.30 per barrel

Operating
Days = 365 per year

Abandonment
Cost = $100,000 per well

Effective
Date = December 30, 2010

 

	 	Heavy
Oil Reserve	 		Revenue	 	 	 
	 							Gas			Before
	 					Gross		(Less			Tax
	 	100%	Gross	Net	Royalty	Gas	Oil	Royalty)	Cap Ex	OpEx	XPV
	Year	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(M$)	(M$)	(M$)	(M$)	(M$)
	2011	-	-	-		-	-	-	-	-	
	2012	232	210	168	42	45	15,049	131	8,951	2,305	3,923
	2013	362	328	263	66	71	23,250	214	-	3,202	20,263
	2014	228	207	165	41	44	14,554	139	-	2,468	12,224
	2015	144	130	104	26	28	9,190	90	-	2,004	7,276
	2016	91	83	66	17	18	5,854	58	115	1,718	4,081
	2017	50	46	36	9	10	3,296	33	-	927	2,401
	2018	32	29	23	6	6	2,152	21	-	829	1,345
	2019	21	19	15	4	4	1,405	14	-	771	647
	2020	13	12	10	2	3	920	9	-	742	187
	2021	1	1	1	0	0	62	1	-	62	0
	Total	1,175	1,064	851	213	229	75,730	710	9,066	15,029	52,346

 

	NPV
    of Future Net Revenue
	
    Before Tax Discounted (in M$) @
	0%	5%	10%	15%	20%
	52,346	44,088	37,634	32,500	28,348

    	15

    	 

    
 

Table
II-8 Guaduas Field Total Proved + Probable Reserve and Net Present Values

Working
Interest = 90.6%

Royalty
rate = 20%

Escalation
Factor - 4% per year based on Colombian Consumer Index

Forecast
Oil Price = see Forecast Oil Prices

CapEx
= $5,500,000 per deviated well and $3,000,000 per vertical well drilling cost

Fixed
OpEx = $446,000 per well per year fixed cost

Variable
OpEx = $6.30 per barrel

Operating
Days = 365 per year

Abandonment
Cost = $100,000 per well

Effective
Date = December 30, 2010

 

	 	Heavy Oil Reserves		 	 Revenue	 	 	 
	 							Gas			Before
	 					Gross		(Less			Tax
	 	100%	Gross	Net	Royalty	Gas	Oil	Royalty)	Cap Ex	OpEx	NPV
	Year	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(M$)	(M$)	(M$)	(M$)	(M$)
	2011	611	554	443	111	119	39,495	311	5,896	7,502	26,407
	2012	896	812	649	162	175	58,105	504	12,249	10,885	35,476
	2013	873	791	633	158	170	55,997	516		11,177	45,336
	2014	621	563	450	113	121	39,608	378		10,007	29,979
	2015	457	414	331	83	89	29,173	285	110	9,310	20,038
	2016	335	304	243	61	65	21,560	215	459	8,027	13,290
	2017	236	214	171	43	46	15,450	154	-	5,652	9,953
	2018	193	175	140	35	38	12,931	129	124	5,561	7,376
	2019	154	140	112	28	30	10,523	105	258	4,867	5,503
	2020	116	105	84	21	23	8,039	80	-	3,478	4,642
	2021	9	8	7	2	2	652	7	-	298	361
	Total	4,501	4,078	3,262	816	877	291,535	2,685	19,096	76,764	198,360

 

	NPV
    of Future Net Revenue
	Before
    Tax Discounted (in MS) @
	0%	5%	10%	15%	20%
	198,360   	 169,581	147,635	130,493	116,805

 

 

    	16

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