OSAGE EXPLORATION & DEVELOPMENT, INC. - FORM 10-K/A - EX-10.25

Attached files

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10-K/A - OSAGE EXPLORATION & DEVELOPMENT, INC.	Form10KA.htm
EX-31.1 - OSAGE EXPLORATION & DEVELOPMENT, INC.	ex31_1.htm
EX-32.2 - OSAGE EXPLORATION & DEVELOPMENT, INC.	ex32_2.htm
EX-31.2 - OSAGE EXPLORATION & DEVELOPMENT, INC.	ex31_2.htm
EX-32.1 - OSAGE EXPLORATION & DEVELOPMENT, INC.	ex32_1.htm
EX-10.24 - OSAGE EXPLORATION & DEVELOPMENT, INC.	ex10_24.htm

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.

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.

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

Figure II-2 Stratigraphic Chart of the Middle Magdalena Valley

Figure II-3 Guaduas Field Delineated Well Development Locations

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

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

Cumulative

Ultimate

Remaining

Contract

Economic

Production

Recoverable

Expiry

Limit

Well Name

Category

(bbl)

Development Well #3

Probable

—

1,689,233

1,020,129

Development Well #4

Probable

—

262,377

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

	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.

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

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$) @

10%

15%

20%

12.166

10.850

9.805

8,959

8,263

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

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

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

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

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

Attached files

OSAGE EXPLORATION & DEVELOPMENT, INC. Reports

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