Investment thesis:  I believe GeoMet, Inc. (GMET) is a severely undervalued natural gas producer currently trading 21.8% below liquidation value despite (1) recently overcoming credit default by reducing its debt to the lowest level in over five years, (2) a LNG tailwind in the natural gas industry, and (3) a potential short/medium-term acquisition catalyst.  Conservatively, I believe the Company is worth $0.33/share.  I believe the investment opportunity exists because (1) the Company is an underfollowed illiquid microcap stock trading below $1.00, (2) the Company’s common shares were delisted from the NASDAQ and currently trades over the counter, (3) an overreaction to the Company’s recent credit problems and (4) decade low US natural gas prices. 

Company description and background on natural gas assets:  GeoMet, Inc. is engaged in the exploration for and development and production of natural gas from coalbed methane (CBM).  The Company’s operations and producing properties are located in the central Appalachian Basin in Virginia and West Virginia.  As of Q2 13, the Company owns 93,000 net acres of CBM and oil and gas development rights. 

The Company operates 298 producing vertical CBM wells in the Pond Creek and Lasher fields in southern West Virginia and southwestern Virginia, in which it owns a 99.0% average working interest.  Net daily sales of gas of these properties averaged 16.0 million cubic feet (MMcf) per day in Q2 13.  The Company operates 44 producing pinnate horizontal CBM wells in central and northern West Virginia in which it owns a 71.6% average working interest.  It also has a 33.7% average working interest in 67 non-operated pinnate horizontal wells in central West Virginia.  Net daily sales of gas of these properties averaged 7.7 MMcf in Q2 13.  As of Q2 13, the Pond Creek and Lasher fields and Pinnate Wells properties had 87,632 MMcf and 6,513 MMcf of proved reserves, respectively.

Background on the supply and demand dynamics of natural gas:  Supply side drivers of natural gas prices include production levels, import and export volumes, and the amount of gas in storage facilities (i.e. storage levels).  Demand side factors that influence prices include economic growth, fluctuations in winter and summer weather, and oil prices. 

Background on historical supply/demand of natural gas:  The US has experienced a fundamental natural gas supply/demand imbalance driven by a surge in production in the past 15 years despite little consumption growth.  Since 1997, natural gas deliveries for residential consumption, commercial consumption, and industrial consumption have declined at rate of 1.2%, 0.7%, and 1.2% annually, respectively while vehicle fuel and electric power consumption have increased 9.6% and 5.5% annually, respectively.  Overall US consumption of natural gas has only increased 0.8% annually from 1997 to 2012.

While consumption of natural gas has increased marginally, production has increased significantly as a result of advances in hydraulic fracturing (fracking).  Fracking is the process of extracting natural gas from shale rock layers that were once unreachable with conventional technologies.  Fracking allows horizontal drilling for the injection of highly pressurized fluids into the shale area to release natural gas.  Shale gas production represented less than 1% of US natural gas production in 2000 and increased to over 20.0% in 2010.  It is expected shale gas production could account for 46.0% of US natural gas production by 2035. 

Decade low natural gas prices have hurt over-levered natural gas producers:  On 04/20/12, the Henry Hub Natural Gas Price hit a multi-year low of $1.82 per million British thermal unit (mmBtu) as a result of (1) an unusually warm winter, (2) high levels of natural gas in storage facilities, and (3) Exxon Mobil’s (XOM) refusal to reduce natural gas production.  On 03/07/12, the US National Climatic Data Center named the 2012 winter season (December, January, and February) as the fourth warmest winter for the contiguous US in over a century.  The 2012 winter season averaged 36.8 degrees Fahrenheit, 3.9 degrees above the 20^th century average.  As a result of the unusually warm 2012 winter, working gas in underground storage at the end of April increased 41.0% to 2,576 billion cubic feet (Bcf).  Furthermore, despite decade low natural gas prices to the point where production was unprofitable, XOM did not follow its competitors in announcing natural gas production cuts (XOM is the largest natural gas producer in the US).  In H1 12, XOM’s production of natural gas excluding the impacts of entitlement volumes and divestments increased 1.0% year-over-year. 

Delisted from NASDAQ:  On 08/03/12, the Company announced it received a notice from The NASDAQ Stock Market that it had failed to maintain a $1.00 minimum stock price for continued listing on the NASDAQ Capital Market.  As a result, its common shares were delisted effective the market open on 08/13/12.  Following the announcement (which occurred pre-market), the Company’s shares declined from $0.25 to $0.21, or 19.4%.  After several days of heavy volume trading, the stock declined another 31.8% to $0.15 on its last day of trading on the NASDAQ.  I believe the significant decline in the Company’s stock price in less than two weeks resulted from significant retail investor selling to avoid holding an illiquid over the counter stock. 

Borrowing base deficiency nearly results in default of debt:  Outstanding borrowings under the Company’s credit facility may not exceed a borrowing base determined by its lenders.  The Company’s borrowing base is recalculated semiannually based on the value of its natural gas reserves.  On 06/21/12, the Company announced that on 06/08/12, its semi-annual borrowing base evaluation resulted in a new base of $115.0 million, $65.0 million (36.1%) lower than the prior base of $180.0 million.  After announcing the existence of its borrowing base deficiency on 06/21/12, the Company’s stock price immediately fell from $0.36 to $0.26 or 27.8%.  At the time of the press release announcement (06/21/12), the Company had borrowings of $148.6 million resulting in a borrowing base deficiency of $33.6 million. 

On 08/09/12, the Company announced that it had amended the facility to extend the time for it to cure the deficiency.  The new credit agreement split the outstanding debt into a tranche A loan in the amount of the borrowing base and a tranche B loan in the amount of the excess.  In addition, all outstanding borrowings are payable on 04/01/14.  Further, the amended credit agreement requires the Company to reduce its borrowings monthly by substantially all of its available excess cash flow and limits capital expenditures to $1.5 million and $1.0 million in FY 12 and FY 13, respectively. 

Sale of Alabama interests eliminates debt overhang:  On 02/26/13, the Company announced that it had engaged Lantana Oil & Gas Partners, a Houston based divesture firm, to sell its coal bed methane interests in Alabama.  The Company’s interest in Alabama included (1) non-operating royalty and/or overriding royalty interests on 1,058 wells in the Black Warrior Basin, (2) a 15.0% working interest in 498 wells in the Black Warrior Basin, and (3) a 100.0% working interest in 252 wells in the Cahaba Basin.  The Company’s interest in its Alabama properties represented 30.0% of net daily sales of natural gas and 38.0% of operating income in FY 12. 

On 05/07/13, the Company announced it had entered into an agreement with a private independent oil and gas company to sell its interests in Alabama for a purchase price of $63.2 million.  The deal was closed on 06/17/13.  The Company utilized $57.0 million of the sales proceeds to repay borrowings under the credit agreement.  As a result of the repayment, outstanding borrowings were reduced to $77.0 million, which was established as the new borrowing base.  As a result of the payment, the borrowing base deficiency was eliminated.  The next scheduled borrowing base determination is expected to occur on or around 12/15/13 and will be based on the Company’s reserves at 06/30/13. 

Stock price reaction on the Company’s credit problems:  When the Company announced it had engaged Lantana to sell its Alabama interests on 02/26/13, the stock price did not react to the news and remained at $0.18 (the stock did not react to the news even a few days after the announcement), suggesting skepticism in the achievability of a sale.  Further, when the Company announced that it had entered into an agreement to sell the Alabama interests on 05/07/13, the stock price did not immediately react and remained constant at $0.18.  Subsequently, the stock price had increased 33.0% to $0.24 (on 05/10/13) after a few days of very heavy volume.  Since then, the stock price has tumbled back down to $0.14.  In my view, the market reaction to the Company’s sale of its Alabama assets and subsequent elimination of the borrowing base deficiency was extremely muted. 

Alabama asset sale suggests the Company trades below liquidation value:  As previously mentioned, on 06/17/13, the Company completed the sale of its Alabama interests for a purchase price of $63.2 million.  The proved reserves of the Alabama assets amounted to 43,036 MMcf.  Accordingly, the sale resulted in a selling price per MMcf of proven reserve of $1.47K.  I applied a 30.0% discount on the expected sales price of the Company’s interests in the Central Appalachia region.  In FY 12, the Central Appalachia assets generated production margins of 22.6%, 720 basis points lower than the Alabama properties.  While I note the Alabama gas properties have different margin profiles to the Company’s interests in the Central Appalachia region, I believe a 30.0% discount is fairly conservative. 

Assuming a 30.0% discount would net a sales price of $96.8 million.  I assumed the sales price would include related equipment and the natural gas inventory.  Based on the Company’s balance sheet as of Q2 13, I applied a 30.0% haircut to the Company’s receivables and other current and long-term other asset accounts, while leaving the liabilities unadjusted.  My analysis suggests a total estimated asset realizable value of $114.0 million with liabilities of $99.3 million, resulting in net assets of $14.7 million.  To calculate shares outstanding, I assumed full dilution of preferred stock, which would add another 43.4 million common shares.  In the end, my liquidation analysis suggests the Company is worth $0.17 per share, a 27.8% premium to the current share price of $0.133 as of 09/24/13. 

Background on LNG:  Liquefied natural gas (LNG) is natural gas that has been cooled to minus 260 degrees Fahrenheit, the point at which gas condenses to a liquid.  When natural gas is cooled into liquid form, its volume is reduced by a factor of 600, which means LNG uses 1/600^th of the space required for the same mass of gas.  This process allows natural gas to be shipped and stored safely and economically to markets around the world. 

Approval process for LNG exports:  For countries that do not have a FTA with the US, the Department of Energy (DOE) is required to grant applications for export authorizations unless the Department finds that the proposed exports “will not be consistent with the public interest”  The DOE considers these applications based on the order received and whether the applicant initiated a pre-filing process with the Federal Energy Regulatory Commission FERC.  After receiving approval from the DOE, developers must also receive approval from the (FERC).  The FERC has jurisdiction over the sitting, construction, and operation of LNG terminals and pipelines.  Aside from DOE and FERC approval, companies must also receive various federal, state, and local approvals. 

Countries that have a free trade agreement with the US include: Australia, Bahrain, Chile, Costa Rica, the Dominican Republic, El Salvador, Guatemala, Honduras, Nicaragua, Israel, Jordan, Morocco, Canada, Mexico, Oman, Peru, and Singapore. 

Background on DOE approved projects:  Currently, there are 15 LNG projects waiting for DOE approval.  Currently four DOE projects have been approved for the export of LNG to non-FTA countries:

·      Cheniere’s Sabine Pass:  On 05/20/11, Cheniere Energy Partners (CQP) announced that it received DOE approval to export 803 Bcf of natural gas per year (equal to 16 million metric tons per annum—mtpa).  Subsequently on 04/16/12, Cheniere announced that it received approval from the FERC to site, construct, and operate facilitates for LNG export at its Sabine Pass LNG terminal in Cameron Parish, LA.  The order authorizes the development of four modular LNG “trains” (LNG trains refer to LNG liquefaction and purification facilities). 

The first two trains are currently under construction and are 40.0% complete as of July 2013.  The Company expects trains 1 and 2 will be operational in late FY 15/FY 16.  Construction on trains 3 and 4 began in May 2013 and are expected to be operational in FY 16/FY 17.  Permitting for trains 5 and 6 began in February 2013 and a FERC application is expected to be completed in H2 13. 

·      Freeport’s liquefaction project:  On 05/17/13, the DOE announced it had approved Freeport LNG’s request to export LNG from its Quintana Island, TX terminal to countries that do not have a free trade agreement with the US.  The DOE authorized Freeport to export up to 511 Bcf of natural gas per year.  Freeport is currently awaiting FERC approval and expects a decision before Q1 14.  Currently, Freeport expects its first LNG liquefaction train to be in service in Q1 18 and its second train to be in service by FY 18. 

·      Dominion’s Cove Point:  On 09/11/13, Dominion Cove Point LP announced it received DOE approval to export 281.1 Bcf of natural gas per year from its terminal in Chesapeake Bay in Lusby, MD to countries that do not have a free trade agreement with the US.  Pending receipt of regulatory approval and permits, Dominion expects to begin construction in FY 14 and begin service of the LNG facility in FY 17.   

·      The Lake Charles liquefaction project:  On 08/08/13, the DOE approved Lake Charles LLC’s application to export 730 Bcf of natural gas to countries that do not have a free trade agreement with the US from its terminal in Lake Charles, LA.  Construction is expected in mid FY 15 with an expected service date in mid FY 19. 

International LNG demand will help domestic natural gas prices:  Collectively, the four approved US LNG export projects can export 2,325.1 Bcf of natural gas annually to non-FTA countries, representing 9.2% of total FY 12 US natural gas production.  I believe significant demand from the Asian natural gas market may improve natural gas pricing in the US.  Aside from Japan, the Republic of Korea, and Taiwan, importing LNG is a relatively new phenomenon for Asian countries.  India began importing in FY 05, China in FY 06, Thailand in FY 11, and Indonesia and Malaysia in FY 12.  The natural gas market in Asia is dominated by long-term contracts in which the price of NG is indexed to oil.  Developing countries in particular require long-term contracts to ensure adequate supply for their growing economies.  The Asian natural gas market is the fastest growing gas market in the world and is expected to become the second largest by FY 15 with 790 Bcm of demand.  Further, BG Group, a multinational oil and gas company, expects Asian LNG exports to increase 5.9% annually from FY 10 to FY 25. 

Significant LNG demand from Japan, China, and Korea:  Currently, Japan and Korea are the two largest LNG importers in the world with China growing significantly as well.  I believe the following data points suggest long-term LNG demand from Asia: 

·   Japan is the world’s largest LNG importer:  According to the US Energy Information Administration (EIA), Japan is the world’s largest importer of LNG, accounting for 33.0% of the global market in FY 11.  In FY 12, Japan produced 176.3 Bcf of natural gas, while consuming 4,361.3 Bcf, resulting in a net import of 4,112.6 Bcf.  Japan relies on LNG imports for virtually all of its gas demand.  Japanese retail gas and electric companies are participating directly in overseas upstream LNG projects to ensure reliable supply.  Osaka Gas, Tokyo Gas, and Toho Gas are Japan’s largest natural gas companies, collectively representing 75.0% of the retail market.   

·    Korea is the world’s second largest LNG importer:  Korea is the second largest importer of LNG.  Korea has no international oil or natural gas pipelines and relies exclusively on tanker shipments of LNG and crude oil.  In FY 11, Korea consumed 1.6 trillion cubic feet (Tcf) of natural gas, a 125.0% increase from 2001.  Korea Gas Corporation (KOGAS) dominates Korea’s gas sector and is the largest LNG importer in the world.  KOGAS operates three out of Korea’s four LNG import terminals.  On 01/10/13, South Korea increased its FY 15 LNG demand forecast by 6.6% to 37.3 million metric tones (mt) of demand.  In FY 11, South Korea imported 1.6 Tcf of LNG, or approximately 32.9 million metric tones.    

·   Growing natural gas demand from China:  China became a net natural gas importer for the first time in over 20 years in 2007.  Since then, it has become a net importer of natural gas.  In FY 10, China imported 1,200 MMcf per day (MMcf/d) of natural gas, which increased 33.3% to 1,600 MMcf/d in FY 11.  Furthermore, the Chinese government is planning to boost the share of natural gas as a percentage of its energy consumption from approximately 5.0% in FY 12 to 10.0% by 2020 to alleviate high pollution from heavy coal use.  I believe this recent policy in conjunction with China’s growing energy demands will drive natural gas consumption in China.   

Recent LNG sales and purchase agreements suggest significant long-term Asian demand for LNG:  I believe these long-term (i.e. 20 year) purchase agreements by large energy companies in both Japan and Korea suggests significant long-term Asian natural gas demand:

·      On 01/30/12, Cheniere announced that it had signed a 20-year LNG Sale and Purchase Agreement (SPA) with KOGAS.  KOGAS agreed to purchase 3.5 mtpa of LNG upon the commencement of train three’s operations. 

·      On 04/01/13, Dominion announced that it had fully subscribed the market capacity of its Dominion Cove Liquefaction project with a 20 year terminal service agreement.  Pacific Summit Energy, LLC, a US affiliate of Japanese trading company Sumitomo Corporation and GAIL Global (USA) LNG LLC, a US affiliate of GAIL (India) Ltd., each contracted for half the capacity of the liquefaction project.  Sumitomo also announced agreements to serve Tokyo Gas Co. and Kansai Electric Power Co.  The Dominion Cove facility has a capacity of 5.25 mtpa of natural gas. 

·      On 07/31/13, Freeport announced that it had executed 20 year liquefaction tolling agreements with Osaka Gas Co, Ltd. and Chubu Electric Power Co, Inc. for 100.0% of the liquefaction capacity of its first train.  The first train has a production capacity of 4.4 mtpa of natural gas. 

LNG exports may lower pricing disparity between domestic and international natural gas prices:  According to research published by the Bipartisan Policy Center, a non-profit think tank, it could cost $2.0 - $5.0/mmBtu to liquefy natural gas and another $1.0 - $3.0/mmBtu to ship it depending on the destination.  Cheniere believes it can liquefy natural gas at a cost of $3.0/mmBtu and ship it to Europe and Asia at a cost of $1.00 mmBtu and $3.00/mmBtu, respectively.  Further, Cheniere believes it will incur fuel/basis cost of $0.60/mmBtu (LNG contracts are generally indexed to oil prices).  Currently, the spot rate of US natural gas is $3.64/mmBtu.  In Europe, the import price of natural gas was $11.12/mmBtu and in Japan it was $16.33/mmBtu in August. 

Assuming liquefaction costs of $5.0/mmBtu, shipping costs of $3.0/mmBtu, and fuel/basis costs of $0.60/mmBtu, it would cost US LNG exporters $8.6/mmBtu (before the cost of acquiring natural gas itself) to export LNG to Japan.  At the current Japanese natural gas import price of $16.33/mmBtu in August, it would be economically profitable to export natural gas to Japan if domestic prices were below $7.73. 

Further, assuming liquefaction costs of $5.0/mmBtu, shipping costs of $1.0/mmBtu, and fuel/basis costs of $0.60/mmBtu, it would cost US LNG exporters $6.6/mmBtu (before the cost of acquiring natural gas itself) to export LNG to Europe.  At the European natural gas import price of $11.12 mmBtu, it would be economically profitable for US LNG exports to export to Europe if domestic prices were below $4.52/mmBtu.  Given potentially significant demand for natural gas in Asia and to a lesser extent in Europe, I believe long-term LNG export demand may help narrow the pricing disparity between US and international natural gas prices. 

The Company’s next borrowing base determination is expected to occur on or around 12/15/13 and will be based on its reserves at 06/30/13.  The Company’s June 2012 borrowing base determination of $115.0 million was based on a 12/31/12  reserve reported prepared by independent reserve engineers.  Based on the monthly average natural gas price (as of the end of each month) for the six months prior to 12/31/12, natural gas prices averaged $3.23/Btu.  The monthly average natural gas price for the six months prior to 06/31/13, was $3.79/Btu.  Given that natural gas prices during the months preceding the Company’s next borrowing base determination are slightly higher than the 12/31/12 reserve report, I believe the Company may receive a favorable revaluation (i.e. significantly higher than the current $77.0 million). 

In February 2012, the Company retained the services of FBR Capital Markets & Co. as its strategic advisor to identify possible strategic alternatives, primarily focused on merger partners.  In its FY 12 10K, the Company represented that as long as it has a borrowing base deficiency, it believes a merger transaction “is not likely”.  On its Q2 13 Conference Call, on 08/15/13, the Company represented the elimination of its borrowing base deficiency allowed it to continue to evaluate strategic alternatives with FBR.  Given the fact that (1) the Company trades below liquidation value, (2) its debt overhang has been removed, and (3) the benefits of operating leverage in consolidating smaller natural gas operators during a period of low prices, I believe there may be a potential short term/medium-term acquisition catalyst. 

Valuation analysis:  In my valuation analysis, I utilized an EV/EBITDA multiple to estimate the Company’s equity value for FY 17.  I assumed the Company would not develop and/or acquire any other natural gas properties and that production volume and sales volume would be 8,970 MMcf (a significant reduction from FY 12 given the sale of the Alabama interests).  To estimate production expenses, I analyzed the $ per MMcf of each type of production expense historically incurred at the projected level of production. 

As of 9/23/13, the Company trades at an EV/EBITDA multiple of 4.0, in line with two of its similarly sized peers, Constellation Energy Partners, CEP (4.4x EV/EBITDA) and PostRock Energy Corporation, PSTR (3.6x EV/EBITDA).  In the base case analysis, I assumed the average realized sales price of natural gas in FY 17 would be $5.00/Btu and the Company would have $50.0 million of debt outstanding.  Further, I assumed full dilution of preferred shares and that the current rate of paid in kind preferred dividends would continue, which would result in a total share count of 101.6 million shares.  Under my base case scenario of an average realized sales price of $5.00 and an EV/EBITDA multiple commensurate with the Company’s current valuation of 4.0x, I estimate the Company’s shares to be worth $0.33 in FY 17.  Base on a sensitivity analysis using a range of average realized sales prices of $3.64 to $6.00 and EV/EBITDA multiples of 3.5x to 6.0x, the Company’s shares could trade up to $1.79. 

Risks to thesis:  I believe the key risks to thesis include: (1) a decline in US natural gas prices, (2) delays in US LNG export facility construction, (3) unfavorable debt renegotiations upon expiration of credit facility in April 2014, (4) LNG export competition, (5) decline in natural gas prices in Europe and Asia, and (6) decline in LNG demand once Japan restarts its nuclear power plants. 

Australia currently has three LNG exporting terminals with a total combined production capacity of 24.1 mtpa.  In addition, there are currently seven large Australian LNG projects under development with service dates ranging from FY 14 to FY 17.  In addition, the British Columbia Province in Canada currently has several proposed LNG projects with potential service dates ranging from FY 15 to FY 23.  I believe as LNG export facilities in these countries come online in the next few years, there will be significant competition to take share in the growing Asian and European demand for natural gas. 

The 03/11/11 earthquake/tsunami in Japan resulted in an immediate shutdown of 12,000 MW of electric generating capacity at four nuclear power stations.  Other energy infrastructure such as electrical grid, refineries, and gas and oil fired power plants were also affected.  On 09/15/13, Kansani Electric Power Co. confirmed its reactor no. 4 was shut down at its Oi plant in the Fukui prefecture in western Japan.  Kansani’s reactor no. 4 was Japan’s last operating nuclear reactor.  Currently all 50 of the Company’s reactors are offline.  Japan has been substituting the loss of nuclear fuel with natural gas, low-sulfur crude oil, and fuel oil.  Japan’s Institute of Energy Economics estimates Japan’s first nuclear reactor may restart as early as July 2014.  I believe that the restart of Japan’s nuclear reactors could potentially result in lower demand for LNG. 

Conclusion:  I believe GMET currently trades 21.8% below liquidation value and could be worth $0.33 per share.  I believe the discount exists because of the fact that the Company was delisted from the NASDAQ, an overreaction to the Company’s recent credit problems, and low US Natural gas prices.   I believe long-term LNG demand from Asia, a new favorable borrowing base determination in December 2013, and a potential acquisition are strong catalysts.