Exhibit 99.1

Blue Dolphin Petroleum Company

Attention: Karen Evans

801 Travis Street, Suite 2100

Houston, TX 77002

An updated reserve analysis was performed for the Langsa “L” and “H” fields, located in TAC-Langsa Offshore Block, Aceh-North Sumatra, Indonesia, and contracted under a Technical Assistance Contract (“TAC”) from Indonesia’s State Oil Company (Pertamina) by Blue Dolphin Petroleum Company (“BDP”). Projections of the reserves and future net revenue to the evaluated interest were based on economic parameters and operating conditions applicable as of January 1, 2012. This report has been prepared pursuant to the guidelines of the United States Securities and Exchange Commission (“SEC”) by American Energy Advisors, Inc.

The effective date of the evaluation is: January 1, 2012.

Reserves and future revenue net to BDP’s interest are estimated to be:

Oil reserves are expressed in barrels, one of which is equivalent to 42 United States gallons. There are no gas reserves.

The reserves and future revenue estimated in this report are for all known potential reserve categories.

Pursuant to applicable SEC rules, the future net revenue is discounted at an annual rate of ten percent to determine the discounted future net revenue. Revenue discounted at 10% is shown only to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

15635 Alton Pkwy, Ste. 295 • Irvine, CA 92618 • Ph: 949-242-3636 • Fax: 949-242-3635

Email: aeasal@aol.com

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January 1, 2012

Cash flow projections do not include any credits or liabilities associated with Indonesian federal income taxes. The working and net revenue interest information was provided by BDP.

Following is a summary of the criteria used for this evaluation:

Field Summary—The Langsa TAC consists of two fields: the “L” field, and the “H” field. Both fields were discovered by Mobil in 1979 and 1980, respectively. To date four wells have been drilled in each field. All four wells in the “L” Field are currently shut in. In the “H” Field two of the wells have been P&A’d, one is “preserved”, and one is currently producing. The wells are completed subsea in 325 ft of water and produce via flexible pipelines to a Floating Production Storage and Offloading barge (“FPSO”).

All wells are completed in a highly-fractured dolomite named the “Malacca Formation” at approximately 5,400’ in the “L” Field, and 5,060’ in the “H” Field. The Malacca thickness ranges from +100’ to +290’, is normal pressured, and it is probable that reservoir pressure is maintained below the bubble point and at near original reservoir pressure by a strong water drive. In fact, the drive is so effective and the secondary fracturing so permeable that coning is a significant problem in the field. All wells flowed naturally, and have been tested and/or produced at oil rates exceeding 3,500 BOPD with no water production. Average GOR ranges 500 to 800 SCF/STBO. Gas production is flared.

Cumulative oil production through December, 2011 is approximately 2,150,000 STBO from the “L” Field, and ~1,789,000 STBO from the “H” Field. Oil gravity is +46º API.

Ownership—BDP owns 7% working interest and 5.20625% net revenue interest, and therefore pays this working interest proportional share of all costs associated with producing and operating the TAC-Langsa Offshore Block. Under the TAC, BDP will be paid 5.20625% of the oil sales until a current total “cost recovery pool” of approximately $59,300,000 (to 100% ownership) plus any additional investments and ongoing operating costs after December, 2012 are recovered.

After the “cost recovery pool” is recovered, BDP’s share of oil sales reverts to 1.795%. Based on the reserve projections herein, reversion is expected to occur during March, 2013.

100% of the ownership of the Langsa TAC reverts back to Pertamina in August, 2017.

Proved Developed Producing (PDP)—The “H” Field has one vertical producing well: #H-4. There are no wells currently producing in the “L” Field. The H-4 well was initially produced at +1,600 BOPD, however due to a downhole problem it is “choked” back, and currently produces an average +375 BOPD, 535 MCFD with no water. It is evident that this production rate is low enough to inhibit coning in this field.

The H-4 has been declining hyperbolically since February, 2001 at a b = .57 exponent, and a current 29.3%/year decline. A sudden increase in Gas-Oil ratio (“GOR”) occurred in January-February, 2011, which could be an indication that reservoir pressure has declined to below the bubble point, or that the gas cap evident on logs has expanded or communicated through fractures to the wellbore. However without current reservoir pressure data and until this GOR exceeds that ratio produced when it was known that the reservoir pressure was below the bubble point (period 2004 thru 2010), a conclusion that the reservoir pressure is not being maintained by a strong water drive can’t be made.

The current producing decline is therefore expected to continue until the water table rises to the bottom of the wellbore. When the oil/water contact reaches the H-4 wellbore, the well will begin loading, and at that point production is projected to decline at 90% per year until the well dies. Currently there is no way to artificially lift wells in the Langsa Fields.

15635 Alton Pkwy., Ste. 295 ¨ Irvine, CA 92618 ¨ Phone (949) 242-3636 ¨ Fax (949) 242-3635

email: aeasal@aol.com

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January 1, 2012

It was determined that if the additional wells included herein as undeveloped locations in the “H” Field were drilled and placed on production by September, 2012 as assumed by BDP, the oil/water contact would reach the H-4 wellbore by approximately April, 2013. It is projected to produce an additional 174,000 BO, and ultimately recover 1,960,000 BO.

Proved Developed Non-Producing (PDNP) –

“L” Field: The L-1 well was the discovery well for the Langsa Fields, and produced about 302,000 BO before being shut in September, 2008 due to problems with the well’s subsea safety valve. It was flowing ~60 BOPD, 1260 BWPD at the time. The cost to repair the faulty valve and restore production would currently be uneconomic, so no reserves were assigned to the L-1.

For this report it was assumed that the wellbore would be preserved and disconnected from the FPSO when a rig is contracted for other well operations in the fields at a cost of $500,000. At which time the other producers in this area of the “L” Field deplete, this vertical well should be re-entered and perforated in the Malacca gas cap, in order to drain any non-recovered “attic” (upstructure) reserves that remain.

The L-4 well was drilled horizontally in the Malacca in early 2007. The lateral portion of the well was placed more than 150’ above the o/w contact, however upon testing it produced nearly 100% water. It is suspected that the well either crossed a fault or a high-permeability fracture that was in communication with the water table. The vertical (or slanted) portion of the hole above the lateral has about 55’ of open hole section.

For this report it was assumed that in December, 2012 the lateral portion of the well would be cemented back to the vertical section and the well returned to production for an approximate cost of $6,320,000. The projected producing rate was restricted to 2,200 BOPD to inhibit coning, but declined at 48% per year to account for reservoir depletion and increasing water cut. The well is estimated to ultimately recover 950,000 BO.

“H” Field: There are no “H” Field proved developed non-producing reserves.

Proved Undeveloped (PUD)—the following reserve calculations are by lease:

“H” Field: The H-3 vertical well was drilled in 1980 by Mobil and was successfully tested as a Malacca producer. At the time, there were no production facilities, so the well was “preserved” for future use with strategically-placed cement plugs. It is located in the northern end of the reservoir, outside of the area that could be drained by the H-4 well prior to the expiration of the Langsa TAC. The H-3 could be re-entered and produced as a vertical well, but without the ability to artificially lift, the well would eventually load up and leave significant up-structure reserves undrained. In addition, coning could be a problem.

This report therefore assumes that the H-3 would be re-entered and kicked-off horizontally near the top of the Malacca zone, resulting in about a 750’ to 1,000’ horizontal well. The re-entry is scheduled for August, 2012, and the estimated cost is $6,320,000 including savings resulting from using the existing wellbore.

The projected producing rate was restricted to 3,000 BOPD, which declines hyperbolically at the same rate as the H-4 well. The well is estimated to ultimately recover 2,653,000 BO.

15635 Alton Pkwy., Ste. 295 ¨ Irvine, CA 92618 ¨ Phone (949) 242-3636 ¨ Fax (949) 242-3635

email: aeasal@aol.com

Page 4 of 6

January 1, 2012

An additional well, the H-5, is necessary to drain the reserves located in the southern portion of the field. Recent re-examination of the seismic data for this field indicates that there is probably a barrier between this proposed location and the H-4, which further supports the need for an additional well to drain the “h” reservoir. The well would be located approximately 2,500’south and 500’ west of the existing H-4 well, and drilled horizontally with a 750’ to 1,000’ lateral. The H-5 is planned to be drilled and placed on production in September, 2012, for an estimated cost of $12, 650,000.

The projected producing rate was restricted to 3,000 BOPD, which declines hyperbolically at the same rate as the H-4 well. The well is estimated to ultimately recover 1,626,000 BO.

“L” Field: The L-2 vertical well was the second well in the Langsa area, and produced about 472,000 BO before being shut in October, 2002. It was producing 490 BOPD and 800 BWPD at the time, and may still be able to be produced. However the well is not currently connected to the FPSO due to a limited number of existing FPSO connection points.

The well was drilled in a structurally lower position compared to the other wells in the field, and without a withdrawal point upstructure in this portion of the reservoir, significant “attic” reserves would remain unrecovered at TAC termination. For this report it was assumed that the L-2 would be re-entered in October, 2012, and a horizontal lateral drilled in a slightly more porous interval of the Malacca, which terminates approximately 1000’ north of the existing wellbore location for an estimated cost of $6,320,000.

The projected producing rate was restricted to 700 BOPD to prevent coning, but declined at 22% per year to account for ongoing skin damage and pressure depletion. The well is estimated to ultimately recover 650,000 BO.

The L-3 Horizontal well recovered 1,375,000 BO before being shut in due to a faulty subsea safety valve in April, 2007. However water production began 8 months after it was placed on production in January, 2005. The lateral was located approximately 150’ above the o/w contact, but +140’ below the gas/oil contact. Water communication thru vertical fractures was suspected.

For this report it was assumed that the L-3 well would be re-entered, and a new lateral drilled to the southwest, close to the g/o contact at -5,382’. This would recover most of the remaining “attic” (upstructure) oil trapped above the current lateral by the strong water drive, as well as the reserves between the current L-3 lateral and the top of the L-4 open-hole section. The L-4 casing shoe is approximately 89’ below the structurally highest location of the top of the Malacca dolomite in this area of the reservoir, and another withdrawal point is needed upstructure to recover oil above this point.

The L-3 is assumed to be drilled in July, 2012, for approximately $1,725,000. The projected producing rate was restricted to 700 BOPD to prevent coning, but declined at 5% per year due to ongoing skin damage. The well is estimated to ultimately recover 1,000,000 BO.

Possible Undeveloped (POSS)—

“L” Field: A development location named the “L-2B” has been identified that is located 1,250’ northwest of the existing L-2 vertical wellbore. According to the 3D seismic interpretation of the “L” Field, this location is fault-separated from the developed portion of the

15635 Alton Pkwy., Ste. 295 ¨ Irvine, CA 92618 ¨ Phone (949) 242-3636 ¨ Fax (949) 242-3635

email: aeasal@aol.com

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January 1, 2012

“L” Field, and structurally lower than the estimated current structural location of the o/w contact. However it is possible that if this portion of the reservoir is not drained, it could ultimately produce 400,000 BO.

The L-2B is assumed to be drilled in January, 2013, for approximately $10,000,000. The projected producing rate was restricted to 700 BOPD to prevent coning, but declined at 13% per year due to reservoir depletion and encroaching water production.

Product Prices: SEC regulations require future revenues for oil and gas properties to be projected on the basis of product prices averaged over the 12 month period prior to the effective date of the report without escalation or reduction.

Oil Pricing – Oil sold from the TAC Langsa area is paid according to the “Indonesia Crude Price” (“ICP”). A review of the previous 18 months of ICP pricing indicates that this index varies at about a 20.9% bonus to NYMEX commodity pricing for sweet, light crude, which was applied to the pricing case used for this evaluation.

For this report AEA used the 12-month crude price average prior to January 1, 2012, which was $95.08/BO.

Gas Pricing – there are no gas sales from this project.

Taxes: There are no production taxes in Indonesia. However there is a 2% VAT tax on expenses paid, which was included for both the fixed and variable costs described below.

Operating/Abandonment Costs: The following costs were applied for the TAC Langsa projections. All such costs were provided by BDP:

Fixed costs – Operating the FPSO costs approximately 1,045,000 per month, which was allocated to the individual wells by a proportion according to each well’s production rate per month. This cost applies as long as the FPSO is being utilized, and does not depend on the number of producing wells. For example – if only one well is producing (which is the current status of the field), the one well carries the entire fixed cost burden.

Variable costs – The operator of the FPSO is paid 3% of the gross revenue produced from the TAC-Langsa, which was calculated and labeled a “transportation cost” in the report.

Operating costs include workover (stimulation, perforating, repairs, etc.) costs.

Abandonment cost – An abandonment cost of $1,250,000 per well was applied when each well depletes, but no later than August, 2017, which is the date of TAC Langsa contract termination. Abandonment cost can be prepaid to be included in the Cost Recovery Pool reversion calculation, which was assumed for this report.

Report Qualifications

The estimated revenues and present value of these revenues are not represented as market value.

Actual individual lease performance may vary from the projections, particularly in comparison to the total composite production from all properties.

15635 Alton Pkwy., Ste. 295 ¨ Irvine, CA 92618 ¨ Phone (949) 242-3636 ¨ Fax (949) 242-3635

email: aeasal@aol.com

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January 1, 2012

Market prices for oil and gas production continue to be subject to a variety of seasonal and market influences resulting in substantial variations in pricing levels. These variations in product prices may affect projections of economically recoverable reserves in some cases.

American Energy Advisors, Inc. is completely independent of BDP and any of its officers or key personnel. Neither I nor anyone closely associated with me or American Energy Advisors, Inc. have any relationship with or ownership of BDP interests that would impair such independence.

If you require additional information or assistance, please do not hesitate to call.

Sincerely:

/s/ STEPHEN A. LIEBERMAN, PETROLEUM ENGINEER    

Stephen A. Lieberman, Petroleum Engineer

15635 Alton Pkwy., Ste. 295 ¨ Irvine, CA 92618 ¨ Phone (949) 242-3636 ¨ Fax (949) 242-3635

email: aeasal@aol.com