Exhibit 99.6

	Gaffney, Cline & Associates, Inc. 1300 Post Oak Blvd., Suite 1000 Houston, TX 77056 Telephone: +1 713 850 9955 www.gaffney-cline.com
VKB/gjh/C2012.04/gcah.181.12	April 27, 2012

Mr. Ramon Elias

Santa Maria Pacific Holdings, LLC

2811 Airport Drive

Santa Maria, CA 93455

Reserve Evaluation Report as of December 31, 2011;

Orcutt Field, Careaga Tract, Diatomite,

Santa Barbara County, California, USA

Dear Mr. Elias:

This reserve evaluation has been prepared by Gaffney, Cline & Associates (GCA) at the request of Santa Maria Pacific Holdings LLC (SMPH) of Santa Maria, California to conduct an independent estimate of the Careaga Tract Diatomite reserves as of December 31, 2011¹. The Careaga Tract has two producing horizons², the Diatomite reservoir and the deeper Monterey Formation reservoir that are owned respectively by SMPH’s wholly-owned subsidiaries, Gitte-Ten, LLC, (GTL) and Orcutt Properties LLC (OPL). The corresponding operators of the respective formations are GTL and Santa Maria Pacific LLC (SMP) which is also a wholly-owned subsidiary of SMPH. The present reserve estimates are compiled on the basis of SMPH’s stated working and net revenue interests.

GCA has conducted a reservoir characterization study to derive the hydrocarbons (crude oil) in-place based on information received from SMPH through April 14, 2012. or Sections 31 and 32 (T9N/R33W) and part of Section 36 (T9N/R34W) of the Careaga Tract, Orcutt field for the Diatomite interval only. GCA also evaluated the reserves as part of the reservoir characterization study. On the basis of technical, field development, commercial and other information made available to us through December 31, 2011 concerning this property unit, we hereby provide the reserve statement given in the tables below.

1 The present evaluation is based on a previous evaluations conducted by GCA as of April 30, 2010 and January 17, 2012.

2 Both producing zones belong to the same formation, the Sisquoc Formation, which is quite extensive in Western and Central California. The shallower zone is a diatomaceous rock, referred to as “Diatomite”, and the deeper zone is a siliceous fractured shale referred to as “Monterey”.

VKB/gjh/C2012.04/gcah.181.12 Santa Maria Pacific Holdings, LLC

Table 1: Statement of Remaining Hydrocarbon Volumes

Diatomite Interval, Sisquoc Formation, Careaga Tract, Orcutt Field, California

As of December 31, 2011

	Gross (100%) Field				Reserves, Net of
	Volumes				Royalties
	Liquids		Gas		Net Oil		Gas
Reserves	(MMstb)		(BCF)		(MMstb)		(BCF)
Proved
Developed Producing		0.37		0.00		0.33		0.00
Developed Non-Producing		0.26		0.00		0.24		0.00
Undeveloped		4.15		0.00		3.77		0.00
Total Proved (1P)		4.78		0.00		4.34		0.00
Proved + Probable (2P)		6.19		0.00		5.62		0.00
Proved + Probable + Possible (3P)		8.24		0.00		7.48		0.00

Table 2: Statement of Contingent Resources Hydrocarbons Volumes

Diatomite Interval, Sisquoc Formation, Careaga Tract, Orcutt Field, California

As of December 31, 2011

	Gross (100%) Field				Resources, Net of
	Volumes				Royalties
	Liquids		Gas		Net Oil		Gas
Contingent Resources	(MMstb)		(BCF)		(MMstb)		(BCF)
1C		8.70		0.00		7.90		0.00
2C		22.73		0.00		20.64		0.00
3C		49.92		0.00		45.32		0.00

Hydrocarbon liquid volumes represent crude oil recovered from the ongoing cyclic steam injection project in the oil-saturated diatomite. Hydrocarbon liquid volumes are reported in millions of stock tank barrels (MMstb). Royalties payable to the rightful royalty interest owners have been deducted from the net volumes. Although there is a small amount of associated gas production, at this point there are no gas sales from the Diatomite and therefore no gas reserves are assigned. The associated gas produced from the Diatomite has not been assigned any commercial value due to impurities that have to be removed prior to the sale. Currently, the diatomite associated gas is flared, and it will be used as lease fuel in the future, if it is determined that the cost associated with the necessary processing can be justified.

The reported reserves and resources are based on estimates and other information provided by SMPH to GCA through April 14, 2012, and included such tests, procedures and adjustments as were considered necessary. All questions that arose during the course of the evaluation were resolved to our satisfaction.

The yearly production and cost projections and the cash flows that contributed to the estimation of the reserves are provided in Appendix I. The cash flows were discounted at 9% discount rate at the request of SMPH.

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VKB/gjh/C2012.04/gcah.181.12 Santa Maria Pacific Holdings, LLC

The Diatomite in the Orcutt field is a hydrous silica rock formation that exhibits high porosity and very low permeability. The formation contains a heavy oil accumulation (about 17 degrees API) and has been produced by cyclic steam injection as shown by the ongoing pilot conducted by SMPH beginning in late 2008 and continuing to the present day. The same diatomite reservoir in the same field has been developed by Breitburn Energy, an offset operator. Many similar projects have been developed in California, using similar techniques in similar diatomite reservoir formations that lend themselves as analogs.

In addition to the pilot program, SMP commissioned in October 2009 the first 16-well module, starting a staged development of the field that is based on building integrated well and facility modules. The 16-well group was expanded to a 20-well group module. The 20-well group module is cycled on a monthly basis: the average monthly steam injection is approximately 1200 BSPD, the average monthly oil production rate is 235 BOPD as of December 31, 2011. The steam injection rate has reached capacity for the in-place steam generation equipment. The steam to oil ratio (SOR) is currently at 4.6 barrels of steam per barrel of oil, which is within reasonable expectations and future SORs are expected in the range of 2 to 5. The method of evaluation is based on using analytical thermal models that match known performance which are then extrapolated into the future. These models relate volume of steam injected to oil produced and can be adjusted to varying geological parameters as development expands from known to untested areas. GCA is applying a geological and petrophysical description in the form of a 3D geological model that was built by GCA in March 2010 and is based on log and core data provided by SMP. In 2011, new well data, logs and core data were provided by SMP and this information was evaluated using the same approach to expand on the earlier reservoir characterization studies and 3D geological model. The updated 3D geological model is further described in the GCA report dated January 17, 2012 and in this report.

Volumes net to SMPH are derived by applying a 99.625% Working Interest (WI) and a corresponding Net Revenue Interest (NRI) of 90.7901960% as advised by SMPH. GCA has not independently verified these fractions.

Yearly cash flow projections are tabulated in Appendix I. The cash flow estimates were used to derive the economic limit for the reserves and to assess the commerciality of the project and do not represent an opinion of asset value.

The US$105.73/Bbl oil price premise used for this evaluation was suggested by SMPH and it is based on the prior 12-month average. The commerciality and economic tests for the December 31, 2011 reserves volumes were based on SMPH’s future scenario of oil which gives a realized price of US$105.73/Bbl after adjustments for quality and transportation. This price was used as of December 31, 2011 and was projected constant over the remainder of the project life. Similarly SMPH has provided the gas prices to be used for steam generation fuel. Gas produced from the deeper Monterey by SMPH will be sold to the Diatomite asset after sulfur removal at a pre-determined price of US$2.76/MMBTU. As demand for steam fuel is expected to rise above the production rates that the Monterey asset can provide, the balance will be covered by purchased gas projected by SMPH to be at US$4.63/MMBTU. That price was estimated by SMPH as the 12-month average SOCAL (PUC) posted price that would apply to this property and is projected to be constant over the project life. Corresponding capital (CAPEX) and operating (OPEX) expenditures are based on estimates provided by SMPH and reviewed by GCA and accepted as reasonable. A discussion of the CAPEX and OPEX is presented in Appendix II.

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VKB/gjh/C2012.04/gcah.181.12 Santa Maria Pacific Holdings, LLC

It is GCA’s opinion that the estimates of total remaining recoverable hydrocarbon liquid volumes as of December 31, 2011 are, in the aggregate, reasonable and the reserves and resources categorization is appropriate and consistent with the reserves and resources definitions set out in the Petroleum Resources Management System (PRMS) approved by the Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers in March 2007 which is referenced in Appendix II.

During 2011 several environmental issues associated with SMPH’s Oil Drilling and Production Plan for 2013 were identified by the Santa Barbara County Commission, which SMPH has elected to address through an Environmental Impact Report (EIR). While this process is ongoing at the time of this report, SMPH has provided documentation to support the progress towards EIR approval. While the timetable for initiation of development has been delayed six months resulting in a production delay until 2014, the evidence provided by SMPH supports a reasonable expectation for EIR approval.

GCA is not aware of any other potential changes in regulations applicable to these fields that could affect the ability of SMPH to produce the estimated reserves.

This assessment has been conducted within the context of GCA’s understanding of SMPH’s petroleum property rights as represented by SMPH’s management. GCA is not in a position to attest to property title, financial interest relationships or encumbrances thereon for any part of the evaluated properties or interests.

There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas reserve engineering and resource assessment must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas reserves or resources prepared by other parties may differ, perhaps materially, from those contained within this report. The accuracy of any Reserve or Resource estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly, Reserve and Resource estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.

For this assignment, GCA served as independent reserve evaluators. The firm’s officers and employees have no direct or indirect interest holding in the property unit. GCA’s remuneration was not in any way contingent on reported reserve estimates.

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VKB/gjh/C2012.04/gcah.181.12 Santa Maria Pacific Holdings, LLC

Finally, please note that GCA reserves the right to approve, in advance, the use and context of the use of any results, statements or opinions expressed in this report. Such approval shall include, but not be confined to, statements or references in documents of a public or semi-public nature such as loan agreements, prospectuses, reserve statements, press releases, etc. This report has been prepared for SMPH and should not be used for purposes other than those for which it is intended.

Very truly yours,

GAFFNEY, CLINE & ASSOCIATES, INC.

Vivian K. Bust, PE, RG

Professional Petroleum Engineer CA 1837

Project Manager

Rawdon J. H. Seager

Principal – Reservoir Engineering

Attachments

Appendices     I:     Yearly Cash Flow Projections

  II: Technical Discussion

  II: Petroleum Resources Management System Definitions and Guidelines

5

APPENDIX I:

Yearly Cash Flow Projections

Date :   04/25/2012     10:43:16AM	ECONOMIC SUMMARY PROJECTION		Total
Partner :                     All Cases
	Orcutt Diatomite-As of 12-31-11
	PDP
	Discount Rate :	9.00
	As of :	01/01/2012

Est. Cum Oil (Mbbl) :	108.55
Est. Cum Gas (MMcf) :	53.91
Est. Cum Water (Mbbl) :	244.23

Year		Oil Gross (Mbbl)		Gas Gross (MMcf)		Oil Net (Mbbl)		Gas Net (MMcf)		Oil Price ($/bbl)		Gas Price ($/Mcf)		Oil & Gas Rev. Net (M$)		Misc. Rev. Net (M$)		Costs Net (M$)		Taxes Net (M$)		Invest. Net (M$)		NonDisc. CF Annual (M$)		Cum Disc. CF (M$)
2012			87.34		0.00		79.30		0.00		105.73		0.00		8,384.43		0.00		3,444.22		111.02		0.00		4,829.19		4,628.81
2013			82.75		0.00		75.13		0.00		105.73		0.00		7,943.17		0.00		3,428.21		105.18		0.00		4,409.77		8,506.31
2014			78.61		0.00		71.37		0.00		105.73		0.00		7,546.27		0.00		3,416.76		99.92		0.00		4,029.59		11,757.20
2015			74.69		0.00		67.81		0.00		105.73		0.00		7,169.21		0.00		3,405.88		94.93		0.00		3,668.40		14,472.55
2016			42.01		0.00		38.14		0.00		105.73		0.00		4,032.47		0.00		2,203.33		53.40		0.00		1,775.74		15,701.64
2017			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		996.25		-996.25		15,090.33
Rem.			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
Total	4.7		365.40		0.00		331.75		0.00		105.73		0.00		35,075.55		0.00		15,898.42		464.45		996.25		17,716.44		15,090.33
Ult.			473.95		53.91

Eco. Indicators
Return on Investment (disc) :	25.685	Present Worth Profile (M$)
Return on Investment (undisc) :	18.783	PW	5.00	% :	16,161.98	PW	20.00	% :	12,743.57
Years to Payout :	0.20	PW	8.00	% :	15,345.48	PW	30.00	% :	11,164.24
Internal Rate of Return (%) :	>1000	PW	10.00	% :	14,843.11	PW	40.00	% :	9,945.37
		PW	12.00	% :	14,371.19	PW	50.00	% :	8,983.30
		PW	15.00	% :	13,715.26	PW	60.00	% :	8,208.80

TRC Standard Eco.rpt 1

Date :   04/25/2012     10:44:21AM	ECONOMIC SUMMARY PROJECTION		Total
Partner :                     All Cases
	Orcutt Diatomite-As of 12-31-11
	PDP+PDNP
	Discount Rate :	9.00
	As of :	01/01/2012

Est. Cum Oil (Mbbl) :	108.55
Est. Cum Gas (MMcf) :	53.91
Est. Cum Water (Mbbl) :	244.23

Year		Oil Gross (Mbbl)		Gas Gross (MMcf)		Oil Net (Mbbl)		Gas Net (MMcf)		Oil Price ($/bbl)		Gas Price ($/Mcf)		Oil & Gas Rev. Net (M$)		Misc. Rev. Net (M$)		Costs Net (M$)		Taxes Net (M$)		Invest. Net (M$)		NonDisc. CF Annual (M$)		Cum Disc. CF (M$)
2012			93.18		0.00		84.60		0.00		105.73		0.00		8,944.24		0.00		3,460.37		118.43		597.75		4,767.68		4,543.42
2013			90.60		0.00		82.25		0.00		105.73		0.00		8,696.65		0.00		3,449.95		115.15		0.00		5,131.54		9,054.10
2014			88.33		0.00		80.20		0.00		105.73		0.00		8,479.38		0.00		3,443.69		112.28		0.00		4,923.42		13,024.74
2015			86.13		0.00		78.19		0.00		105.73		0.00		8,267.54		0.00		3,437.57		109.47		0.00		4,720.49		16,517.60
2016			84.20		0.00		76.45		0.00		105.73		0.00		8,082.80		0.00		3,435.52		107.03		0.00		4,540.25		19,599.63
2017			81.87		0.00		74.33		0.00		105.73		0.00		7,859.06		0.00		3,425.79		104.06		0.00		4,329.21		22,295.51
2018			77.37		0.00		70.24		0.00		105.73		0.00		7,426.46		0.00		3,405.23		98.34		0.00		3,922.90		24,541.18
2019			23.84		0.00		21.64		0.00		105.73		0.00		2,288.40		0.00		1,640.21		30.30		0.00		617.90		24,873.99
2020			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		996.25		-996.25		24,395.58
Rem.			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
Total	7.5		625.51		0.00		567.90		0.00		105.73		0.00		60,044.54		0.00		25,698.33		795.07		1,594.00		31,957.14		24,395.58
Ult.			734.06		53.91

Eco. Indicators
Return on Investment (disc) :	51.994	Present Worth Profile (M$)
Return on Investment (undisc) :	33.077	PW	5.00	% :	27,342.22	PW	20.00	% :	18,594.84
Years to Payout :	0.30	PW	8.00	% :	25,079.98	PW	30.00	% :	15,178.54
Internal Rate of Return (%) :	>1000	PW	10.00	% :	23,742.64	PW	40.00	% :	12,798.51
		PW	12.00	% :	22,523.88	PW	50.00	% :	11,070.87
		PW	15.00	% :	20,889.69	PW	60.00	% :	9,772.44

TRC Standard Eco.rpt 1

Date :   04/25/2012     10:45:48AM	ECONOMIC SUMMARY PROJECTION		Total
Partner :                     All Cases
	Orcutt Diatomite-As of 12-31-11
	PUD
	Discount Rate :	9.00
	As of :	01/01/2012

Est. Cum Oil (Mbbl) :	0.00
Est. Cum Gas (MMcf) :	0.00
Est. Cum Water (Mbbl) :	0.00

Year		Oil Gross (Mbbl)		Gas Gross (MMcf)		Oil Net (Mbbl)		Gas Net (MMcf)		Oil Price ($/bbl)		Gas Price ($/Mcf)		Oil & Gas Rev. Net (M$)		Misc. Rev. Net (M$)		Costs Net (M$)		Taxes Net (M$)		Invest. Net (M$)		NonDisc. CF Annual (M$)		Cum Disc. CF (M$)
2012			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
2013			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		89,791.36		-89,791.36		-76,874.02
2014			197.90		0.00		179.67		0.00		105.73		0.00		18,996.62		0.00		10,129.87		251.54		15,441.90		-6,826.69		-82,938.32
2015			466.30		0.00		423.35		0.00		105.73		0.00		44,761.00		0.00		15,353.75		592.69		0.00		28,814.56		-61,711.66
2016			593.66		0.00		538.99		0.00		105.73		0.00		56,986.99		0.00		16,576.91		754.58		0.00		39,655.50		-34,821.20
2017			632.80		0.00		574.52		0.00		105.73		0.00		60,744.13		0.00		16,683.23		804.33		5,504.28		37,752.30		-11,442.11
2018			612.52		0.00		556.11		0.00		105.73		0.00		58,797.69		0.00		16,623.30		778.56		0.00		41,395.83		12,217.82
2019			524.46		0.00		476.16		0.00		105.73		0.00		50,344.21		0.00		16,363.06		666.62		0.00		33,314.53		29,709.13
2020			525.35		0.00		476.96		0.00		105.73		0.00		50,429.36		0.00		16,373.65		667.75		0.00		33,387.96		45,722.60
2021			395.21		0.00		358.81		0.00		105.73		0.00		37,936.90		0.00		15,007.28		502.33		0.00		22,427.29		55,689.34
2022			192.37		0.00		174.66		0.00		105.73		0.00		18,466.36		0.00		11,968.27		244.52		0.00		6,253.57		58,255.37
2023			10.85		0.00		9.85		0.00		105.73		0.00		1,041.13		0.00		982.03		13.79		0.00		45.32		58,272.86
2024			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		5,479.38		-5,479.38		56,338.50
Rem.			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
Total	11.1		4,151.41		0.00		3,769.08		0.00		105.73		0.00		398,504.41		0.00		136,061.36		5,276.71		116,216.93		140,949.42		56,338.50
Ult.			4,151.41		0.00

Eco. Indicators
Return on Investment (disc) :	1.592	Present Worth Profile (M$)
Return on Investment (undisc) :	2.213	PW	5.00	% :	86,460.92	PW	20.00	% :	8,992.33
Years to Payout :	5.91	PW	8.00	% :	62,992.39	PW	30.00	% :	-10,387.23
Internal Rate of Return (%) :	23.77	PW	10.00	% :	50,189.65	PW	40.00	% :	-19,496.27
		PW	12.00	% :	39,245.95	PW	50.00	% :	-23,521.59
		PW	15.00	% :	25,701.22	PW	60.00	% :	-24,943.73

TRC Standard Eco.rpt 1

Date :   04/25/2012     11:17:32AM	ECONOMIC SUMMARY PROJECTION		Total
Partner :                     All Cases
	Orcutt Diatomite-As of 12-31-11
	1P
	Discount Rate :	9.00
	As of :	01/01/2012

Est. Cum Oil (Mbbl) :	108.55
Est. Cum Gas (MMcf) :	53.91
Est. Cum Water (Mbbl) :	244.23

Year		Oil Gross (Mbbl)		Gas Gross (MMcf)		Oil Net (Mbbl)		Gas Net (MMcf)		Oil Price ($/bbl)		Gas Price ($/Mcf)		Oil & Gas Rev. Net (M$)		Misc. Rev. Net (M$)		Costs Net (M$)		Taxes Net (M$)		Invest. Net (M$)		NonDisc. CF Annual (M$)		Cum Disc. CF (M$)
2012			93.18		0.00		84.60		0.00		105.73		0.00		8,944.24		0.00		3,460.37		118.43		597.75		4,767.68		4,543.42
2013			90.60		0.00		82.25		0.00		105.73		0.00		8,696.65		0.00		3,449.95		115.15		89,791.36		-84,659.82		-67,819.92
2014			286.23		0.00		259.87		0.00		105.73		0.00		27,476.01		0.00		13,573.56		363.82		15,441.90		-1,903.27		-69,913.58
2015			552.42		0.00		501.55		0.00		105.73		0.00		53,028.54		0.00		18,791.33		702.17		0.00		33,535.05		-45,194.06
2016			677.86		0.00		615.43		0.00		105.73		0.00		65,069.79		0.00		20,012.43		861.61		0.00		44,195.75		-15,221.57
2017			714.67		0.00		648.85		0.00		105.73		0.00		68,603.19		0.00		20,109.02		908.39		5,504.28		42,081.50		10,853.40
2018			689.89		0.00		626.35		0.00		105.73		0.00		66,224.16		0.00		20,028.54		876.89		0.00		45,318.73		36,759.00
2019			548.30		0.00		497.80		0.00		105.73		0.00		52,632.62		0.00		18,003.27		696.92		0.00		33,932.43		54,583.12
2020			525.35		0.00		476.96		0.00		105.73		0.00		50,429.36		0.00		16,373.65		667.75		996.25		32,391.71		70,118.18
2021			395.21		0.00		358.81		0.00		105.73		0.00		37,936.90		0.00		15,007.28		502.33		0.00		22,427.29		80,084.92
2022			192.37		0.00		174.66		0.00		105.73		0.00		18,466.36		0.00		11,968.27		244.52		0.00		6,253.57		82,650.96
2023			10.85		0.00		9.85		0.00		105.73		0.00		1,041.13		0.00		982.03		13.79		0.00		45.32		82,668.45
2024			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		5,479.38		-5,479.38		80,734.08
Rem.			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
Total	11.1		4,776.93		0.00		4,336.98		0.00		105.73		0.00		458,548.94		0.00		161,759.69		6,071.77		117,810.93		172,906.55		80,734.08
Ult.			4,885.48		53.91

Eco. Indicators
Return on Investment (disc) :	1.844	Present Worth Profile (M$)
Return on Investment (undisc) :	2.475	PW	5.00% :	113,803.14	PW	20.00% :	27,587.17
Years to Payout :	5.34	PW	8.00% :	88,072.36	PW	30.00% :	4,791.31
Internal Rate of Return (%) :	33.43	PW	10.00% :	73,932.28	PW	40.00% :	-6,697.77
		PW	12.00% :	61,769.83	PW	50.00% :	-12,450.71
		PW	15.00% :	46,590.90	PW	60.00% :	-15,171.29

TRC Standard Eco.rpt 1

Date :   04/25/2012     11:20:46AM	ECONOMIC SUMMARY PROJECTION		Total
Partner :                     All Cases
	Orcutt Diatomite-As of 12-31-11
	2P
	Discount Rate :	9.00
	As of :	01/01/2012

Est. Cum Oil (Mbbl) :	108.55
Est. Cum Gas (MMcf) :	53.91
Est. Cum Water (Mbbl) :	244.23

Year		Oil Gross (Mbbl)		Gas Gross (MMcf)		Oil Net (Mbbl)		Gas Net (MMcf)		Oil Price ($/bbl)		Gas Price ($/Mcf)		Oil & Gas Rev. Net (M$)		Misc. Rev. Net (M$)		Costs Net (M$)		Taxes Net (M$)		Invest. Net (M$)		NonDisc. CF Annual (M$)		Cum Disc. CF (M$)
2012			93.18		0.00		84.60		0.00		105.73		0.00		8,944.24		0.00		3,460.37		118.43		597.75		4,767.68		4,543.42
2013			90.60		0.00		82.25		0.00		105.73		0.00		8,696.65		0.00		3,449.95		115.15		89,791.36		-84,659.82		-67,819.92
2014			354.23		0.00		321.60		0.00		105.73		0.00		34,003.01		0.00		13,791.66		450.24		15,441.90		4,319.21		-64,989.00
2015			729.61		0.00		662.41		0.00		105.73		0.00		70,036.87		0.00		19,386.13		927.38		0.00		49,723.36		-28,338.47
2016			867.47		0.00		787.58		0.00		105.73		0.00		83,270.92		0.00		20,518.44		1,102.61		0.00		61,649.87		13,485.48
2017			906.98		0.00		823.45		0.00		105.73		0.00		87,063.41		0.00		20,623.14		1,152.83		6,550.34		58,737.09		49,892.37
2018			887.95		0.00		806.17		0.00		105.73		0.00		85,236.43		0.00		20,559.66		1,128.64		0.00		63,548.13		86,217.72
2019			740.80		0.00		672.57		0.00		105.73		0.00		71,111.07		0.00		18,517.96		941.60		0.00		51,651.52		113,331.71
2020			670.18		0.00		608.45		0.00		105.73		0.00		64,331.76		0.00		16,748.70		851.83		2,042.31		44,688.91		134,783.81
2021			523.36		0.00		475.16		0.00		105.73		0.00		50,238.14		0.00		15,414.92		665.22		0.00		34,158.01		149,949.75
2022			256.21		0.00		232.62		0.00		105.73		0.00		24,594.42		0.00		12,815.47		325.66		0.00		11,453.29		154,624.75
2023			72.29		0.00		65.63		0.00		105.73		0.00		6,939.49		0.00		5,810.13		91.89		1,195.50		-158.03		154,561.67
2024			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		5,479.38		-5,479.38		152,694.57
Rem.			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
Total	11.5		6,192.84		0.00		5,622.50		0.00		105.73		0.00		594,466.42		0.00		171,096.54		7,871.49		121,098.55		294,399.83		152,694.57
Ult.			6,301.40		53.91

Eco. Indicators
Return on Investment (disc) :	2.754	Present Worth Profile (M$)
Return on Investment (undisc) :	3.713	PW	5.00% :	203,757.96	PW	20.00% :	69,258.52
Years to Payout :	4.68	PW	8.00% :	164,059.77	PW	30.00% :	32,005.52
Internal Rate of Return (%) :	51.36	PW	10.00% :	142,138.05	PW	40.00% :	12,039.36
		PW	12.00% :	123,197.44	PW	50.00% :	1,007.86
		PW	15.00% :	99,407.54	PW	60.00% :	-5,166.39

TRC Standard Eco.rpt 1

Date :   04/25/2012     11:34:29AM	ECONOMIC SUMMARY PROJECTION		Total
Partner :                     All Cases
	Orcutt Diatomite-As of 12-31-11
	3P
	Discount Rate :	9.00
	As of :	01/01/2012

Est. Cum Oil (Mbbl) :	108.55
Est. Cum Gas (MMcf) :	53.91
Est. Cum Water (Mbbl) :	244.23

Year		Oil Gross (Mbbl)		Gas Gross (MMcf)		Oil Net (Mbbl)		Gas Net (MMcf)		Oil Price ($/bbl)		Gas Price ($/Mcf)		Oil & Gas Rev. Net (M$)		Misc. Rev. Net (M$)		Costs Net (M$)		Taxes Net (M$)		Invest. Net (M$)		NonDisc. CF Annual (M$)		Cum Disc. CF (M$)
2012			93.18		0.00		84.60		0.00		105.73		0.00		8,944.24		0.00		3,460.37		118.43		597.75		4,767.68		4,543.42
2013			90.60		0.00		82.25		0.00		105.73		0.00		8,696.65		0.00		3,449.95		115.15		89,791.36		-84,659.82		-67,819.92
2014			444.08		0.00		403.18		0.00		105.73		0.00		42,628.61		0.00		14,057.21		564.46		15,441.90		12,565.04		-58,460.51
2015			960.83		0.00		872.34		0.00		105.73		0.00		92,232.64		0.00		20,069.45		1,221.28		0.00		70,941.91		-6,173.67
2016			1,145.47		0.00		1,039.98		0.00		105.73		0.00		109,956.73		0.00		21,339.98		1,455.97		0.00		87,160.78		52,969.46
2017			1,181.25		0.00		1,072.46		0.00		105.73		0.00		113,390.79		0.00		21,433.65		1,501.44		6,550.34		83,905.35		105,042.22
2018			1,177.32		0.00		1,068.89		0.00		105.73		0.00		113,014.25		0.00		21,414.82		1,496.45		0.00		90,102.97		156,530.20
2019			1,036.85		0.00		941.35		0.00		105.73		0.00		99,529.36		0.00		19,392.84		1,317.90		0.00		78,818.63		197,885.01
2020			918.00		0.00		833.45		0.00		105.73		0.00		88,121.00		0.00		17,481.07		1,166.83		2,042.31		67,430.78		230,301.52
2021			724.04		0.00		657.35		0.00		105.73		0.00		69,502.01		0.00		16,202.47		920.30		0.00		52,379.24		253,533.57
2022			341.69		0.00		310.22		0.00		105.73		0.00		32,799.96		0.00		13,112.17		434.31		0.00		19,253.47		261,386.19
2023			127.99		0.00		116.20		0.00		105.73		0.00		12,285.60		0.00		8,811.00		162.68		1,195.50		2,116.42		262,183.00
2024			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		5,479.38		-5,479.38		260,355.99
Rem.			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
Total	11.7		8,241.29		0.00		7,482.28		0.00		105.73		0.00		791,101.82		0.00		180,224.98		10,475.20		121,098.55		479,303.09		260,355.99
Ult.			8,349.84		53.91

Eco. Indicators
Return on Investment (disc) :	3.678	Present Worth Profile (M$)
Return on Investment (undisc) :	4.978	PW	5.00% :	339,309.99	PW	20.00% :	130,560.55
Years to Payout :	4.14	PW	8.00% :	277,943.39	PW	30.00% :	71,544.73
Internal Rate of Return (%) :	74.70	PW	10.00% :	244,008.82	PW	40.00% :	38,983.05
		PW	12.00% :	214,643.07	PW	50.00% :	20,195.00
		PW	15.00% :	177,666.71	PW	60.00% :	8,993.83

TRC Standard Eco.rpt 1

Date :   04/25/2012     12:06:11PM	ECONOMIC SUMMARY PROJECTION		Total
Partner :                     All Cases
	Orcutt Diatomite-As of 12-31-11
	1C
	Discount Rate :	9.00
	As of :	01/01/2012

Est. Cum Oil (Mbbl) :	0.00
Est. Cum Gas (MMcf) :	0.00
Est. Cum Water (Mbbl) :	0.00

Year		Oil Gross (Mbbl)		Gas Gross (MMcf)		Oil Net (Mbbl)		Gas Net (MMcf)		Oil Price ($/bbl)		Gas Price ($/Mcf)		Oil & Gas Rev. Net (M$)		Misc. Rev. Net (M$)		Costs Net (M$)		Taxes Net (M$)		Invest. Net (M$)		NonDisc. CF Annual (M$)		Cum Disc. CF (M$)
2012			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
2013			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		41,009.49		-41,009.49		-35,520.68
2014			201.92		0.00		183.32		0.00		105.73		0.00		19,382.42		0.00		9,852.61		256.65		13,334.28		-4,061.12		-39,225.97
2015			502.35		0.00		456.09		0.00		105.73		0.00		48,222.20		0.00		15,378.12		638.52		77,976.66		-45,771.09		-72,515.30
2016			830.98		0.00		754.45		0.00		105.73		0.00		79,768.02		0.00		22,941.01		1,056.23		16,217.64		39,553.14		-46,001.87
2017			1,088.57		0.00		988.31		0.00		105.73		0.00		104,494.14		0.00		29,165.57		1,383.64		0.00		73,944.93		-64.16
2018			1,270.63		0.00		1,153.61		0.00		105.73		0.00		121,971.11		0.00		30,672.06		1,615.05		0.00		89,684.00		51,123.12
2019			1,273.41		0.00		1,156.14		0.00		105.73		0.00		122,238.16		0.00		30,892.82		1,618.59		0.00		89,726.76		98,157.51
2020			1,188.40		0.00		1,078.95		0.00		105.73		0.00		114,077.74		0.00		30,652.91		1,510.53		0.00		81,914.30		137,579.47
2021			965.08		0.00		876.20		0.00		105.73		0.00		92,640.32		0.00		28,846.09		1,226.68		0.00		62,567.56		165,231.85
2022			730.78		0.00		663.48		0.00		105.73		0.00		70,149.28		0.00		26,304.05		928.87		0.00		42,916.37		182,652.12
2023			503.02		0.00		456.69		0.00		105.73		0.00		48,285.94		0.00		24,118.98		639.37		0.00		23,527.59		191,452.77
2024			144.97		0.00		131.61		0.00		105.73		0.00		13,915.65		0.00		11,023.71		184.26		0.00		2,707.68		192,400.68
2025			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		10,049.00		-10,049.00		189,259.76
Rem.			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
Total	12.5		8,700.11		0.00		7,898.85		0.00		105.73		0.00		835,144.99		0.00		259,847.93		11,058.38		158,587.06		405,651.61		189,259.76
Ult.			8,700.11		0.00

Eco. Indicators
Return on Investment (disc) :	2.604	Present Worth Profile (M$)
Return on Investment (undisc) :	3.558	PW	5.00% :	264,719.89	PW	20.00% :	74,723.04
Years to Payout :	5.85	PW	8.00% :	205,763.28	PW	30.00% :	28,992.38
Internal Rate of Return (%) :	45.54	PW	10.00% :	174,095.89	PW	40.00% :	6,920.20
		PW	12.00% :	147,319.21	PW	50.00% :	-4,000.61
		PW	15.00% :	114,562.00	PW	60.00% :	-9,385.08

TRC Standard Eco.rpt 1

Date :   04/25/2012     1:16:29PM	ECONOMIC SUMMARY PROJECTION		Total
Partner :                     All Cases
	Orcutt Diatomite-As of 12-31-11
	2C
	Discount Rate :	9.00
	As of :	01/01/2012

Est. Cum Oil (Mbbl) :	0.00
Est. Cum Gas (MMcf) :	0.00
Est. Cum Water (Mbbl) :	0.00

Year		Oil Gross (Mbbl)		Gas Gross (MMcf)		Oil Net (Mbbl)		Gas Net (MMcf)		Oil Price ($/bbl)		Gas Price ($/Mcf)		Oil & Gas Rev. Net (M$)		Misc. Rev. Net (M$)		Costs Net (M$)		Taxes Net (M$)		Invest. Net (M$)		NonDisc. CF Annual (M$)		Cum Disc. CF (M$)
2012			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
2013			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		42,282.69		-42,282.69		-36,623.47
2014			269.15		0.00		244.37		0.00		105.73		0.00		25,836.76		0.00		10,339.81		342.11		79,264.41		-64,109.58		-89,975.06
2015			679.00		0.00		616.47		0.00		105.73		0.00		65,179.08		0.00		16,341.84		863.05		25,929.72		22,044.47		-73,781.14
2016			1,027.00		0.00		932.42		0.00		105.73		0.00		98,584.46		0.00		27,294.79		1,305.38		58,353.32		11,630.97		-66,921.46
2017			1,396.08		0.00		1,267.50		0.00		105.73		0.00		134,012.98		0.00		42,734.13		1,774.50		133,632.69		-44,128.34		-95,361.45
2018			2,047.98		0.00		1,859.36		0.00		105.73		0.00		196,590.48		0.00		61,298.98		2,603.11		68,066.75		64,621.64		-59,457.85
2019			2,640.48		0.00		2,397.30		0.00		105.73		0.00		253,466.50		0.00		77,345.41		3,356.22		28,694.96		144,069.91		15,634.50
2020			2,785.14		0.00		2,528.63		0.00		105.73		0.00		267,352.29		0.00		81,912.23		3,540.09		9,713.44		172,186.53		98,472.69
2021			2,759.61		0.00		2,505.46		0.00		105.73		0.00		264,901.89		0.00		81,783.06		3,507.64		3,168.08		176,443.12		176,329.19
2022			2,632.76		0.00		2,390.29		0.00		105.73		0.00		252,725.24		0.00		81,408.19		3,346.40		7,446.97		160,523.68		241,370.96
2023			2,446.46		0.00		2,221.15		0.00		105.73		0.00		234,842.13		0.00		80,730.90		3,109.61		0.00		151,001.63		297,480.29
2024			2,019.70		0.00		1,833.69		0.00		105.73		0.00		193,876.38		0.00		76,320.75		2,567.17		0.00		114,988.47		336,774.10
2025			1,375.56		0.00		1,248.87		0.00		105.73		0.00		132,043.22		0.00		68,439.85		1,748.42		0.00		61,854.95		356,180.03
2026			655.82		0.00		595.42		0.00		105.73		0.00		62,953.78		0.00		46,478.51		833.59		0.00		15,641.68		360,759.97
Rem.			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		27,695.75		-27,695.75		-7,130.48
Total	14.7		22,734.75		0.00		20,640.93		0.00		105.73		0.00		2,182,365.19		0.00		752,428.45		28,897.30		484,248.77		916,790.68		353,629.49
Ult.			22,734.75		0.00

Eco. Indicators
Return on Investment (disc) :	2.116	Present Worth Profile (M$)
Return on Investment (undisc) :	2.893	PW	5.00% :	538,825.23	PW	20.00% :	105,197.94
Years to Payout :	7.76	PW	8.00% :	392,915.10	PW	30.00% :	23,085.11
Internal Rate of Return (%) :	35.98	PW	10.00% :	318,196.94	PW	40.00% :	-9,954.06
		PW	12.00% :	257,304.34	PW	50.00% :	-23,124.58
		PW	15.00% :	186,061.33	PW	60.00% :	-27,795.85

TRC Standard Eco.rpt 1

Date :   04/25/2012     1:50:38PM	ECONOMIC SUMMARY PROJECTION		Total
Partner :                     All Cases
	Orcutt Diatomite-As of 12-31-11
	3C
	Discount Rate :	9.00
	As of :	01/01/2012

Est. Cum Oil (Mbbl) :	0.00
Est. Cum Gas (MMcf) :	0.00
Est. Cum Water (Mbbl) :	0.00

Year		Oil Gross (Mbbl)		Gas Gross (MMcf)		Oil Net (Mbbl)		Gas Net (MMcf)		Oil Price ($/bbl)		Gas Price ($/Mcf)		Oil & Gas Rev. Net (M$)		Misc. Rev. Net (M$)		Costs Net (M$)		Taxes Net (M$)		Invest. Net (M$)		NonDisc. CF Annual (M$)		Cum Disc. CF (M$)
2012			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
2013			0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00		42,282.69		-42,282.69		-36,623.47
2014			369.49		0.00		335.46		0.00		105.73		0.00		35,468.07		0.00		10,612.30		3,661.77		84,630.47		-63,436.47		-89,594.02
2015			909.91		0.00		826.11		0.00		105.73		0.00		87,344.80		0.00		16,966.79		9,017.59		25,926.73		35,433.69		-63,531.55
2016			1,303.68		0.00		1,183.61		0.00		105.73		0.00		125,143.56		0.00		34,138.31		12,919.98		61,342.06		16,743.22		-53,118.86
2017			1,669.86		0.00		1,516.07		0.00		105.73		0.00		160,294.28		0.00		45,775.47		16,548.99		138,998.75		-41,028.93		-79,470.55
2018			2,407.58		0.00		2,185.85		0.00		105.73		0.00		231,109.85		0.00		66,495.12		23,860.08		65,225.37		75,529.28		-37,227.05
2019			2,957.59		0.00		2,685.20		0.00		105.73		0.00		283,906.38		0.00		84,437.70		29,310.86		56,587.20		113,570.62		21,512.94
2020			3,357.97		0.00		3,048.71		0.00		105.73		0.00		322,339.66		0.00		100,847.77		33,278.76		148,313.76		39,899.37		39,977.34
2021			4,163.28		0.00		3,779.85		0.00		105.73		0.00		399,643.16		0.00		119,152.14		41,259.67		65,825.19		173,406.17		115,605.65
2022			5,045.20		0.00		4,580.55		0.00		105.73		0.00		484,301.04		0.00		135,819.53		49,999.86		39,923.10		258,558.56		219,825.85
2023			5,319.04		0.00		4,829.17		0.00		105.73		0.00		510,588.10		0.00		141,294.71		52,713.77		4,483.13		312,096.50		335,692.01
2024			5,344.52		0.00		4,852.30		0.00		105.73		0.00		513,033.79		0.00		141,468.42		52,966.26		9,713.44		308,885.68		440,951.67
2025			5,189.63		0.00		4,711.67		0.00		105.73		0.00		498,165.04		0.00		140,188.40		51,431.19		5,349.86		301,195.59		535,159.89
2026			4,404.17		0.00		3,998.55		0.00		105.73		0.00		422,767.18		0.00		131,425.62		43,647.02		6,151.84		241,542.69		604,533.94
Rem.			7,478.18		0.00		6,789.45		0.00		105.73		0.00		717,848.90		0.00		307,829.34		74,111.64		46,275.81		289,632.12		75,647.16
Total	17.8		49,920.10		0.00		45,322.56		0.00		105.73		0.00		4,791,953.82		0.00		1,476,451.61		494,727.42		801,029.40		2,019,745.39		680,181.10
Ult.			49,920.10		0.00

Eco. Indicators
Return on Investment (disc) :	2.481	Present Worth Profile (M$)
Return on Investment (undisc) :	3.521	PW	5.00% :	1,092,351.29	PW	20.00% :	189,904.25
Years to Payout :	9.22	PW	8.00% :	764,809.17	PW	30.00% :	51,448.18
Internal Rate of Return (%) :	40.43	PW	10.00% :	605,292.49	PW	40.00% :	1,115.65
		PW	12.00% :	480,036.12	PW	50.00% :	-17,881.50
		PW	15.00% :	339,657.94	PW	60.00% :	-24,739.86

TRC Standard Eco.rpt 1

APPENDIX II:

Technical Discussion

TECHNICAL DISCUSSION

Introduction

The Careaga Tract is located in the southeastern part of the Orcutt Field which is located onshore in northwestern Santa Barbara County, California, near the city of Santa Maria. SMP has an interest in the Careaga Tract that constitutes the southern portion of the Orcutt field (Figure 1).

Figure 1: Location of the Orcutt Field and the Careaga Tract outline

The following display (Figure 2) outlines the various leases that SMP has acquired and holds within the Careaga Tract (within the green outline): Phoenix Energy, L.L.C., 609 acres below 3,000 ft. (within the blue), Gitte-Ten, L.L.C., 177 acres below 3,000 ft. (within the red), Orcutt Properties, L.L.C., 4,024 acres above 3,000 ft. (within the green). The Careaga Tract lies in Section 36 of T9N R34W, Sections 31 and 32 of T9N R33W, and Sections 5, 6, 7, and 8 of T8N R33W SBBM.

GCA has been informed that SMP, as Operator, represents 99.625% of the WI in Sections 31 and 32 of T9N R33W of the Careaga tract, which covers the subject hydrocarbon reserves. A rectangular area covering 1,100 acres on the northern part of the Careaga tract in Sections 31 and 32 has been defined as the Target Development Area (TDA) within the lease that SMP operates, manages, controls and represents. The most productive interval of the Diatomite reservoir is shallower than 2,200 feet below ground surface, as in greater depths there is a diagenetic change of the Opal-A mineralogy to an Opal-CT mineralogy with a respective reduction in porosity.

Figure 2: Location of the Careaga Tract Leases

Study Objective

The objective of the reserve and resource evaluation study was to integrate the 3D geologic model with petrophysical property modeling of the four (4) hydrocarbon bearing zones of the Diatomite reservoir within the Sisquoc formation of SMP’s lease area in Orcutt Field.

3D Structure and Property modeling

Structural modeling of the diatomite horizon surfaces are approximately the same and include the 90-31-rd well data pertinent to the diatomite interval. A deterministic minimum tension gridding algorithm was used for well-to-well areal modeling of horizon surfaces. Structure surfaces and the top of the density transition zone (from Opal-A to Opal-CT) surface are shown in the following figure (Figure 3).

Figure: 3: Geologic Model of Diatomite Horizons for 670, 870, 1010, 1130 and Dns_Tz.

The number of layers per zone was selected to approximate the vertical heterogeneity indicated by well log lithology, porosity and resistivity profiles. A zone is defined here as the interval between consecutive horizon surfaces (tops). Intervals 670, 870, 1010 and 1130 correspond to 3D modeling zones of 4, 5, 6, and 7. A deterministic moving average inverse distance squared algorithm was used for well-to-well spacial modeling of properties.

Oil In-place

In estimating the oil in-place three cutoffs were applied to estimate net pay: 1) Clay content (represented by the shale fraction identified from the gamma ray (GR) log (Ish)) cutoff of 50% bulk volume was used to identify reservoir rock quality; 2) porosity range between 20 and 70% bulk volume; and, 3) Archie water saturation cutoff of less than 80% pore volume. Total porosity was used in the Archie water saturation model. The Ish ratio used for this study is defined as:

Ish=[GR_log - GR_clean]/[GR_shale – GR_clean] where GR_shale is 120 API and GR_clean is 25 API. A detailed petrophysical analysis is presented in GCA report C731.03 dated April 23, 2010.

The STOIIP was calculated for zone 6, zones 5 and 6 and zones 4, 5, 6 and 7 across designated areas of the pilot (20-well group), confidence polygon, and within specified resource concentration boundaries. Table 1 summarizes STOIIP for the plan of development well spacing, and for a range of recovery efficiencies.

Table 1: STOIIP

Area	Petrel Zone		Petrel STOIIP MMSTB		Area acres		Petrel Volm Calc MSTB/AC		WSP 0.33 ac /well		RF= 30% bbl/well		RF= 40% bbl/well		RF= 60% bbl/well
PDP 20-well group		6		1.5		8		188		0.33		18,563		24,750		37,125
PDP 20-well group		5 & 6		2.5		8		313		0.33		30,938		41,250		61,875
PDP 20-well group		4,5,6 & 7		3.0		8		375		0.33		37,125		49,500		74,250
1PUD — Confidence Polygon		6		45		291		155		0.33		15,309		20,412		30,619
2PUD — Confidence Polygon		5 & 6		86		291		296		0.33		29,258		39,010		58,515
3PUD — Confidence Polygon		4,5,6 & 7		97		291		333		0.33		33,000		44,000		66,000
Boundary 200 MSTB/AC		5 & 6		134		438		306		0.33		30,292		40,389		60,584
Boundary 250 MSTB/AC		5 & 6		108		323		334		0.33		33,102		44,136		66,204
Boundary 200 MSTB/AC		4,5,6 & 7		153		469		326		0.33		32,296		43,062		64,593
Boundary 250 MSTB/AC		4,5,6 & 7		120		338		355		0.33		35,148		46,864		70,296

Notes:

SMP Diatomite, Orcutt Field:

Reservoir Quality for the Dec. 31, 2009, 2010 and 2011 reserve audits and reservoir characterization studies are based on the well data and log-core correlations. Reservoir Quality is based on 3 cutoff criteria

1) Reservoir quality intervals are identified by using an Ish cutoff of Ish < 0.50. (Ish = (GR - GR_cln)/(GR_sh - GR_cln) where GR_cln = 25 API and GR_sh=120 API)

2) Porosity (range of total porosity 20 to 70% bv)

3) Saturation (Archie Water Saturation model using total porosity, and SW cutoff range of less than or equal to 80% pv)

Resource Evaluation Methodology

According to SMP’s development plans, up to 1,300 new wells may be drilled in the course of the next 15-30 years at a regular 1/3-acre well spacing. The constraints for their development are the land availability, locations that can be easily prepared in that terrain and resource extension. The following map shows the locations that SMP has identified for future development.

Figure 4: Future Well Locations at Identified by SMPH

Based on current oil in place maps, GCA has concluded that up to 929 of these wells can be placed in areas of the asset which should have at least 200 Bbl/acre oil in place (considering four zones; 4, 5, 6, and 7). Based on GCA’s estimates wells placed at that resource concentration would yield at least 20,000-25,000 Bbl per well and should be commercial. The following figures show the placement of wells that lie within designated reserve and contingent resources areas. It also distinguishes the wells that were considered in the 2C and 3C contingent estimate into 3 types (A, B and C) according to the resource concentration.

Resource concentration maps were converted from STOIIP into units of MSTB/acre for each zone. These are shown in the following figures (Figures 5, 6, 7 and 8). The confidence polygon is identified on each figure. The confidence polygon includes the area of the highest oil saturated target intervals 870 and 1010 (zones 5 and 6) within the well control on the lease and it includes the cyclic steam injection pilot test area.

Figure 5: Proved Developed Producing (PDP) in Pilot area and Confidence Polygon

Figure 6: Proved Undeveloped (PUD) Reserves and Contingent Resources (1C)

Figure 7: Contingent Resources (2C)

Figure 8: Contingent Resources (3C)

The current development plan for Orcutt diatomite was provided by SMPH in detail for the next 5 years. This provides for drilling 110 wells in 2014 and up to 120 wells yearly thereafter. The steaming capacity of the diatomite development is planned to be expanded through regulatory air emissions trading programs (cap-and-trade). Once the peak rate is achieved, development would proceed by adding 120 wells annually for as long as it is required to exhaust the resource. For the proved case, GCA did not assume drilling more than 120 new wells in any given year.

GCA used analytical thermodynamic models that relate steam injection to oil production. The first step was to match and forecast the performance of the 20-well pilot area where production is from interval 1010 (zone 6). The following figure shows the producing oil rate match at the beginning of the forecast (Figure 9).

Figure 9: Match of 20-well Pilot Area with Thermal Analytical Model

In building the above model, GCA used the parameters of zone 6 in describing the rock properties and resource concentration. Minor adjustments were made by adjusting heat losses to nearby rock and through production of hot fluids. This model suggests an effective decline of 5%/year for the first 52 months followed by an 84%/year decline afterwards. A similar decline scheme was used to extrapolate the performance of the 20-well group that is currently producing. The model was extended to predict the performance for the same 20-well group by recompleting the above interval 870 (zone 5). GCA then used the same and similar parameters to construct individual well types for the 1P scenario assuming similar performance as the 20- well pilot area for all the 110 new undeveloped wells that were qualified as proved undeveloped (PUD). The methodology was also applied to the Contingent Resources.

Steam performance comparisons were made between SMPH’s historical production and GCA’s forecast for the 1P, and analogous diatomite performance at Orcutt (Breitburn) and at Midway-Sunset (TRC). According to the following figure, the SMPH historical and forecasted 1P closely tracks the Brietburn trend. Thus, the thermal analytical model projections are deemed reasonable within the context of this evaluation and the projected profiles were adopted for economic evaluation.

Figure 10: Steam Performance Comparisons

Economic Parameters

The cost estimates used for the commerciality test and for the economic limit calculation were based on expense estimates made by SMPH on a unit basis. In order to simplify other cost estimates provided by SMPH, GCA used a combination of fixed and variable costs per barrel of oil and steam that matches closely the overall SMPH cost projections. The GCA fixed field expenses were adjusted to closely match the overall expenses forecast by SMPH for year 2012 at 3.44 MM$. The OPEX unit costs are presented in the following table (Table 2).

Table 2: OPEX

OPEX	Unit Costs
Fixed Well (1/1/ 2012 to ECL), US$/well/mo		4,659.00
Fixed Well (4/1/2014 to ECL), US$/well/mo		7,992.33
Fixed Field, US$/case		74,400.00
Variable Oil, $/bbl		2.78
Variable Steam & Fuel for Steam & Water Transport, US$/bbl		2.74
Variable Steam & Fuel (No Water Transport), US$/bbl		1.49
(for PUD 110-well expansion and beyond)
Variable Waste Water Handling, US$/bbl		0.15

Note: Annual Recurring CAPEX was converted to OPEX 3333.33 US$/well/mo as approved by SMPH

The capital expenditures costs for the 110-expansion for the proved reserves and the contingent resources were estimated based on unit costs and one-time costs in the following table (Table 3). SMPH estimates that each new well will cost about US$850,000 to be drilled and completed. SMPH estimates that 15% of the wells could be redrilled or an equivalent amount spent on repairs that could address dilation/compaction damages. The drilling program will be executed by multiple drill rigs that will be contracted. It is assumed that up to 120 wells can be drilled within 1 year according to the drilling and production schedule provided by SMPH. Each 85 MMBtu/hr steam generator planned for the project expansion will support 60 to 80 steam injection wells and is estimated to cost approximately US$3,000,000 . The wells will be drilled and completed according to the drilling schedule; however, the first day of production will be dependent on the completion of the associated steam generator facilities and wellhead hookup allowing the scheduled wells to come online as the development progresses.

Table 3: CAPEX

CAPEX	Unit Costs
Permitting & Regulatory, US$/well		17,545
Drilling, US$/well		368,290
Well Hookup, US$/well		77,273
Oil Facilities, US$/well		135,453
Steam & Water Facilities, US$/well		109,377
Steam Generator (85 MMBTU/hr ), US$/unit		3,000,000
Workovers, US$/well		30,000
Redrill (15% of drilled wells), US$/well		325,000
2 Horizontal Water Disposal Wells US$/well		2,300,000
P&A Diatomite wells, US$/well		50,000
One-time CAPEX Costs for 110-well Expansion	One-time Costs
Infrastructure, US$		14,437,800
CTS Environmental Mitigation, US$		1,000,000
P&A Monterey Wells for Diatomite Expansion, US$		3,018,400
Step-out Information Wells (5), US$		1,000,000

The oil produced by SMPH has about a 16 API gravity and it is sold close to California’s heavy crude index. The US$105.73/Bbl oil price premise used for this evaluation was suggested by SMPH and it is based on the 12-month average. The commerciality and economic tests for the December 31, 2011 reserves volumes were based on SMPH’s future scenario of oil which gives a realized price of US$105.73/Bbl after adjustments for quality and transportation. This price was used as of December 31, 2011 and was projected constant over the remainder of the project life. The economic evaluation reports are in Appendix I.

APPENDIX III:

Petroleum Resources Management System Definitions and Guidelines

Society of Petroleum Engineers, World Petroleum Council, American Association of

Petroleum Geologists and Society of Petroleum Evaluation Engineers

Petroleum Resources Management System

Definitions and Guidelines (³)

March 2007

Preamble

Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within the Earth’s crust. Resource assessments estimate total quantities in known and yet-to-be-discovered accumulations; resources evaluations are focused on those quantities that can potentially be recovered and marketed by commercial projects. A petroleum resources management system provides a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework.

International efforts to standardize the definition of petroleum resources and how they are estimated began in the 1930s. Early guidance focused on Proved Reserves. Building on work initiated by the Society of Petroleum Evaluation Engineers (SPEE), SPE published definitions for all Reserves categories in 1987. In the same year, the World Petroleum Council (WPC, then known as the World Petroleum Congress), working independently, published Reserves definitions that were strikingly similar. In 1997, the two organizations jointly released a single set of definitions for Reserves that could be used worldwide. In 2000, the American Association of Petroleum Geologists (AAPG), SPE and WPC jointly developed a classification system for all petroleum resources. This was followed by additional supporting documents: supplemental application evaluation guidelines (2001) and a glossary of terms utilized in Resources definitions (2005). SPE also published standards for estimating and auditing reserves information (revised 2007).

These definitions and the related classification system are now in common use internationally within the petroleum industry. They provide a measure of comparability and reduce the subjective nature of resources estimation. However, the technologies employed in petroleum exploration, development, production and processing continue to evolve and improve. The SPE Oil and Gas Reserves Committee works closely with other organizations to maintain the definitions and issues periodic revisions to keep current with evolving technologies and changing commercial opportunities.

The SPE PRMS document consolidates, builds on, and replaces guidance previously contained in the 1997 Petroleum Reserves Definitions, the 2000 Petroleum Resources Classification and Definitions publications, and the 2001 “Guidelines for the Evaluation of Petroleum Reserves and Resources”; the latter document remains a valuable source of more detailed background information.

These definitions and guidelines are designed to provide a common reference for the international petroleum industry, including national reporting and regulatory disclosure agencies, and to support petroleum project and portfolio management requirements. They are intended to improve clarity in global communications regarding petroleum resources. It is expected that SPE PRMS will be supplemented with industry education programs and application guides addressing their implementation in a wide spectrum of technical and/or commercial settings.

It is understood that these definitions and guidelines allow flexibility for users and agencies to tailor application for their particular needs; however, any modifications to the guidance contained herein should be clearly identified. The definitions and guidelines contained in this document must not be construed as modifying the interpretation or application of any existing regulatory reporting requirements.

The full text of the SPE PRMS Definitions and Guidelines can be viewed at:

www.spe.org/specma/binary/files/6859916Petroleum_Resources_Management_System_2007.pdf

³  These Definitions and Guidelines are extracted from the Society of Petroleum Engineers / World Petroleum Council / American Association of Petroleum Geologists / Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) Petroleum Resources Management System document (“SPE PRMS”), approved in March 2007.

RESERVES

Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.

Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.

On Production

The development project is currently producing and selling petroleum to market.

The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project.

Approved for Development

A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.

At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells.

Justified for Development

Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained.

In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time.

Proved Reserves

Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.

If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes:

(1) the area delineated by drilling and defined by fluid contacts, if any, and

(2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that the locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive. Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.

Probable Reserves

Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.

It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.

Possible Reserves

Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves.

The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.

Probable and Possible Reserves

(See above for separate criteria for Probable Reserves and Possible Reserves.)

The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or 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 minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations.

Developed Reserves

Developed Reserves are expected quantities to be recovered from existing wells and facilities.

Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate but which have not yet started producing,

(2) wells which were shut-in for market conditions or pipeline connections, or

(3) wells not capable of production for mechanical reasons.

Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Undeveloped Reserves

Undeveloped Reserves are quantities expected to be recovered through future investments:

(1) from new wells on undrilled acreage in known accumulations,

(2) from deepening existing wells to a different (but known) reservoir,

(3) from infill wells that will increase recovery, or

(4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to:

(a) recomplete an existing well, or

(b) install production or transportation facilities for primary or improved recovery projects.

CONTINGENT RESOURCES

Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies.

Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

Development Pending

A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.

The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production.

Development Unclarified or on Hold

A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay.

The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies.

Development Not Viable

A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential.

The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future.

PROSPECTIVE RESOURCES

Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.

Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. t is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration.

Prospect

A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target.

Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program.

Lead

A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect.

Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios.

Play

A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects.

Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios.

RESOURCES CLASSIFICATION

PROJECT MATURITY