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March 20, 2015

To the Shareholders of Biloxi Marsh Lands Corporation:

The following is a discussion of the results of operations of the Company for the year ended December 31, 2014. The annual revenue breakdown is as follows: 2014 revenue from oil and gas production from our fee lands was $534,652 compared to revenue of $636,189 in 2013.

Dividend and interest income for 2014 was $202,819, compared to $164,275 for 2013. In 2014, the Company realized a cumulative gain from the sale of investment securities of $1,717,041 compared to a cumulative gain in the amount of $2,072,125 in 2013. Meanwhile, for the year 2014, total revenues included a $1,371,185 loss emanating from the Company’s investment in B&L Exploration, LLC (B&L). This compares to a loss of $1,740,193 from B&L in the prior year. As an operating oil and gas entity, B&L’s results included deductions for depreciation, depletion and amortization (DD&A) costs relating to its ongoing exploration activities. Our share of these DD&A expenses was $992,684 and $927,415 for 2014 and 2013, respectively. Total revenues for 2014 were $1,122,376 compared to $4,351,080 during 2013. 2013 revenues included a non-recurring gain under the BP Deepwater Horizon Economic and Property Damages Settlement Program in the amount of $3,189,681. Expenses for the year totaled $945,848, slightly lower than the prior year’s expenses of $1,091,414.

For the year, the Company had net income of $202,411 or $.08 per share compared to net income of $2,450,729 or $.90 per share in 2013.

The end of the year proved reserve study commissioned by the Company and completed by T. J. Smith & Company, Inc., an independent reservoir engineer, estimates that as of December 31, 2014 the Company’s “Developed Producing” (PDP) reserves were .339 billion cubic feet of natural gas (BCFG) and 2,800 barrels of oil.

Please find the following table showing the Company’s proved reserves as of December 31, 2014:

Proved Reserves as of December 31, 2014 (3)

Producing (PDP)
(Dollars in thousands)
Net Proved Reserves (1)

Natural Gas (BCF): …………………..0.339

Oil and Condensate, Net MBO: …………………..2.8
Estimated Future Net Revenues (before income taxes) (2): …………………. $ 1,660 (4)

Estimated Discounted Future Net Revenues (before income taxes) (2): ……. $ 1,205 (4)
(1) In general, our engineers based their estimates of economically recoverable oil and natural gas reserves and of the future net revenues therefrom on a number of variable factors and assumptions, such as historical production from the subject properties, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices, all of which may vary considerably from actual results. Therefore, the actual production, revenues, and severance taxes with respect to reserves likely will vary from such estimates, and such variances could be material.

Estimates with respect to proved reserves that may be developed and produced in the future are often based on volumetric calculations and by analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history, and subsequent evaluation of the same reserves, based on production history, will result in variations, which may be substantial, in the estimated reserves.

Proved Reserves included herein conform to the definition as set forth in the Securities and Exchange Commission (SEC) Regulation, S-X Part 210.4-10 (a) as revised and adopted effective January 1, 2010. The future net revenues are those revenues attributable to the Company’s interest in the underlying wells less severance taxes. The discounted future net revenue is based on a discount rate of 10 percent per annum. The forecasts assume that no changes in the current economic conditions, sales demand or costs will occur in the future. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market values of the estimated reserves.

PDP reserves were estimated for each producing well based on extrapolation of the historical producing trend.

(2) Base product prices were determined based on the 12 month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 month period prior to December 31, 2014. The oil price of $94.99 per barrel is based on the West Texas Intermediate (WTI), Cushing, Oklahoma spot prices. The natural gas price of $4.35 per MMBtu is based on the Henry Hub gas daily prices. Price differentials were applied as appropriate to adjust these base prices of oil and gas to the specific field market situation.

(3) The Company has no control over operations and maintains only a landowner’s mineral royalty interest. Please see footnote (i) following the final paragraph of this letter for a warning concerning forward-looking information.

(4) The value of the proved reserves “Undiscounted, M$” and “Discounted at 10%, M$” includes a minimal amount of Oil and Condensate as well as Natural Gas Liquids.

We caution our shareholders and interested parties that the December 31, 2014 SEC prices used in the foregoing proved reserve report are significantly higher than the current price of oil and natural gas.

As of December 31, 2014, the combined gross daily production rate from 8 wells operated by our mineral lessees was approximately 3.679 million cubic feet of natural gas (mmcfg) and 157 barrels of oil per day (BOPD) with net daily production accruing to the Company of approximately .435 mmcfg and 3 BOPD. The foregoing production includes four wells producing from S/L 16158 in which we own a small interest.

As previously reported, we received a settlement payment during 2013 for our wetlands real property claim under the BP Deepwater Horizon Economic and Property Damages Settlement Program. We have been advised by our legal counsel that an additional limited recovery under the settlement may be expected, but as of this time it is difficult to determine the timing and amount of the additional settlement, if any.

In June 2014, we announced the completion of our stock buyback program with the acquisition of a total of 67,500 shares of our common stock since the inception of the program in September 2008. During the course of completing the buyback program, the opportunity to purchase additional shares of common stock presented itself. We successfully negotiated the purchase of an additional 151,900 shares in two separate private transactions. Since September of 2008, the total number of shares purchased by the Company as treasury stock is 219,400. We paid an average price of $12.62 for these shares of common stock since the inception of the buyback program. As of the time of this press release, we are not actively seeking to repurchase any additional shares of our common stock.

The Company continues to pursue a claim for damages against the US Army Corps of Engineers for property loss and damage related to the Mississippi River Gulf Outlet (MRGO).

Meanwhile, another reserve study completed by T. J. Smith & Company, Inc. estimates that B&L’s proved reserves as of December 31, 2014 were approximately 9.4 BCFG and approximately 197 thousand barrels of oil (MBBL) which compared to 9.0 BCFG and 215 MBBL as of December 31, 2013. It should be noted that a significant component of B&L’s proved reserves as of December 31, 2014 are Proved Undeveloped (PUD). As is necessary with all PUD reserves, a well or wells must be drilled and completed to fully develop these PUD reserves. The foregoing reserves do not include any reserves attributable to FM O&G’s Highlander Area Well in which B&L is contractually entitled to a 1.5% ORRI.

Additionally, as of December 31, 2014, B&L’s gross daily production was approximately 4.655 mmcfg and 336 barrels of oil from 7 wells with 1.685 mmcfg and 43 barrels of oil per day accruing to B&L.
Freeport-McMoRan Inc. (NYSE: FCX) announced on March 16, 2015 “that following production testing on Freeport-McMoRan Oil & Gas’ (FM O&G) Highlander discovery, located onshore in South Louisiana in the Inboard Lower Tertiary/Cretaceous trend, independent reserve engineers provided estimates of proved reserves totaling approximately 38 billion cubic feet (Bcf) of natural gas” ….. “associated with the initial well. Independent reserve engineers estimates of proved, probable and possible reserves for the initial well totaled approximately 197 Bcf of natural gas. In addition, based on work performed to date, independent reserve engineers estimate additional gross resources for the Highlander field exceeding 2 trillion cubic feet (Tcf).
As previously reported, the February 2015 production test, which was performed in the Cretaceous/Tuscaloosa section, utilized expanded testing equipment and indicated a flow rate of approximately 75 million cubic feet of natural gas per day (MMcf/d), approximately 37 MMcf/d”… “on a 42/64th choke with flowing tubing pressure of 10,300 pounds per square inch. FM O&G commenced production in late February 2015. FM O&G plans to install additional amine processing facilities to accommodate the higher rates.
A second well location has been identified and future plans will be determined pending review of performance of the first well. FM O&G has identified multiple prospects in the Highlander area which provide opportunities for future development of the field. FM O&G controls rights to more than 50,000 gross acres.
The Highlander discovery well was drilled to a total depth of approximately 29,400 feet in the first of quarter 2014. Wireline log and core data obtained from the Wilcox and Cretaceous sand packages indicated favorable reservoir characteristics with approximately 150 feet of net pay.”
B&L has been assigned and is contractually entitled to a 1.5% of 8/8ths overriding royalty interest (ORRI) in the Lomond North/Highlander discovery well and in all mineral leases obtained by FM O&G in its Highlander project area located in Iberia, St. Martin, Assumption and Iberville Parishes, Louisiana. This means that 1.5% of the foregoing reserves estimate by FM O&G’s independent reservoir engineers would accrue to B&L if and when the Highlander field is fully developed by FM O&G.

B&L completed construction of production facilities and the flowline for the Welder No. 1 well and placed the well on production December 12, 2014. As of March 18, 2015, the Welder No. 1 well had gross production of approximately 1.52 mmcfg and 8 BOPD. B&L has 100% working interest in the Welder No. 1 well. B&L’s management is pleased with the production rates on B&L’s Welder No. 1 well which are better than anticipated. Due to the decline in commodity prices during the fourth quarter of 2014, B&L’s management is reevaluating each of its drilling projects. B&L’s management believes that in the event of additional discoveries in the Lago Verde project area each well should continue to be economically viable due to the relatively shallow target depths and lower costs of drilling. While commencement of drilling may be delayed to allow B&L to take advantage of declining drilling costs, B&L’s management anticipates that additional prospects in the Lago Verde project area will be drilled during 2015.

As previously reported, B&L assembled a mineral lease position in Allen and Beauregard Parishes, Louisiana, targeting the Wilcox sand interval which has been a historically prolific oil producing interval in this area using conventional well completion techniques. Based on technical information, B&L believes that reservoir stimulation using hydraulic fracturing could result in the discovery and production of significant oil reserves that were not accessible in the past using conventional well completion techniques. To assist in development of this Wilcox project, B&L placed the majority of the working interest with Petro Harvester Oil & Gas LLC, headquartered in Plano, Texas. Petro Harvester has experience in drilling and stimulating Wilcox wells in neighboring parishes. B&L retained a 15.75% working interest in the Wilcox project. This project is currently being reevaluated by B&L’s management in the context of the current lower oil price environment.

B&L was organized as a limited liability Company (LLC) under the laws of Louisiana in July of 2006. B&L’s members are the Company and Lake Eugenie Land & Development, Inc. (LKEU), which have membership percentages of 75% and 25%, respectively.
During its meeting held on December 11, 2014, the Board of Directors declared a dividend of $.40 per outstanding share of common stock payable on Tuesday, December 30, 2014 to shareholders of record at the close of business on Monday, December 22, 2014. This represents a total cash dividend payment of $1,014,011 or $.40 per share in 2014. Since 2002, we have paid approximately $54,905,000 in total dividends. With our fee land based production depleting and no new meaningful wells being drilled on our fee lands, it will be difficult to maintain the level of dividends paid since 2002.
With this said, using 3D seismic data in our possession and other means, we are constantly working on developing the minerals located below our fee lands. One important step taken is joining a consortium of oil companies which retained the University of Texas Bureau of Economic Geology (BEG) to evaluate and quantify chlorite coating on cores taken from the Woodbine and Tuscaloosa sand intervals throughout south Texas and Louisiana, including the ARCO – Biloxi Marsh Land P-2 well which was drilled on the Company’s property during the early 1980s and penetrated the Tuscaloosa sand interval. The results of the BEG’s study indicate significant preserved porosity and permeability in the P-2 well’s conventional cores due to chlorite coating of the Tuscaloosa sand grains and the presence of reservoir bitumen in the Tuscaloosa sand interval. This could prove to be significant as we move forward with our attempts to have the conventional Tuscaloosa sand interval further tested and developed beneath our fee lands. Meanwhile, we are focusing on developing reserves outside of our fee acreage through our investment in B&L. In its current stage of growth and continued reinvestment in its drilling program, B&L should not be viewed as a dividend producing entity.

Please remember to visit our website,, to obtain general information about the Company as well as historical annual reports and all press releases. We strongly recommend that all interested parties become familiar with the information available on the Company’s website: .

The announcement by FM O&G concerning the flow tests of its Lomond North/Highlander discovery well and the reserves attributable to the well and the field are very encouraging. We are not aware of the well’s current production rates or FM O&G’s development plans beyond information that has been made public, but if the Highlander area is successfully developed with multiple wells, over time the Highlander area could be very significant to B&L. The fact that the Lomond North/Highlander well has been flow tested at high commercial rates from the Tuscaloosa sand interval outside of the traditional “Tuscaloosa Trend” could possibly mean an increase in future drilling activity throughout coastal Louisiana, including on the Company’s fee lands. As stated earlier, we are taking various steps to further understand the potential for exploration and development of the Tuscaloosa sand interval beneath our fee lands. 2015 will prove to be a challenging year due to lower commodity prices. With a strong balance sheet, no debt and significant proved reserves from our investment in B&L, we are positioned favorably for the upcoming year.


William B. Rudolf
President and Chief Executive Officer
Metairie, Louisiana
Email: [email protected]

This letter contains forward-looking statements regarding oil and gas discoveries, oil and gas exploration, development and production activities and reserves. Accuracy of the forward-looking statements depends on assumptions about events that change over time and is thus susceptible to periodic change based on actual experience and new developments. The Company cautions readers that it assumes no obligation to update or publicly release any revisions to the forward-looking statements in this report. Important factors that might cause future results to differ from these forward-looking statements include: variations in the market prices of oil and natural gas; drilling results; unanticipated fluctuations in flow rates of producing wells; oil and natural gas reserves expectations; the ability to satisfy future cash obligations and environmental costs; additional drilling, and general exploration and development risks and hazards. Readers are cautioned not to place undue reliance on forward-looking statements made by or on behalf of the Company. Each such statement speaks only as of the day it was made. The factors described above cannot be controlled by the Company. When used in this report, the words “hopeful”, “believes”, “estimates”, “plans”, “expects”, “could”, “should”, “outlook”, “possibly” and “anticipates” and similar expressions as they relate to the Company or its management are intended to identify forward-looking statements.