UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10K/A

Amendment No. 3

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

Or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to _____________

Commission file number: 001-14665

(Exact name of registrant as specified in its charter)

17304 Preston Rd, Suite 700, Dallas, Texas 75252

(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (972) 818-0720

Securities registered pursuant to Section 12(b) of this Act:

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (ss. 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (ss. 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check One).

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The aggregate market value of the voting common stock held by non-affiliates of the registrant at March 31, 2014 was $7,185,208.

Number of shares of the registrant’s common stock outstanding at March 31, 2014 was 22,453,773.

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2013

TABLE OF CONTENTS

Forward-Looking Statements

Certain statements contained in this Annual Report on Form 10-K are not statements of historical fact and constitute forward-looking statements within the meaning of the various provisions of the Securities Act of 1933, as amended, (the “Securities Act”) and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including, without limitation, the statements specifically identified as forward-looking statements within this report. Many of these statements contain risk factors as well. In addition, certain statements in our future filings with the SEC, in press releases, and in oral and written statements made by or with our approvals which are not statements of historical fact constitute forward-looking statements within the meaning of the Securities Act and the Exchange Act. Examples of forward-looking statements, include, but are not limited to: (i) projections of capital expenditures, revenues, income or loss, earnings or loss per share, capital structure, and other financial items, (ii) statements about the plans and objectives of our management or board of directors including those relating to planned development of our oil and gas properties, (iii) statements of future economic performance and (iv) statements of assumptions underlying such statements. Words such as “believes,” “anticipates,” “expects,” “intends,” “targeted,” “may,” “will” “might,” “should,” “plan,” “predict,” “project,” “envision,” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

Such forward-looking statements speak only as of the date on which such statements are made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made to reflect the occurrence of unanticipated events.

See also “Risk Factors.”

CERTAIN DEFINITIONS

Unless the context otherwise requires, the terms “we,” “us,” “our,” “ours,” “the Company” or “TransCoastal” when used in this report refer to TransCoastal Corporation, together with our consolidated operating subsidiaries. When the context requires, we refer to these entities separately.

We have included below the definitions for certain terms used in this report:

AFE – Authority for expenditure.

After payout – With respect to an oil or natural gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered.

Bbl – One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bbls/d or BOPD – Barrels per day.

Bcf – Billion cubic feet.

Bcfe – Billion cubic feet equivalent, determined using the ratio of six thousand cubic feet (Mcf) of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Before payout – With respect to an oil and natural gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered.

Behind-pipe reserves – Those reserves expected to be recovered from completion interval(s) not yet open but still behind casing in existing wells.

BOE – Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

Carried interest – A contractual arrangement, usually in a drilling project, whereby all or a portion of the working interest cost participation of the project originator is paid for by another party in exchange for earning an interest in such project.

Completion – The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Compression – A force that tends to shorten or squeeze, decreasing volume or increasing pressure.

DD&A – Depreciation, depletion and amortization.

Developed acreage – The number of acres which are allotted or assignable to producing wells or wells capable of production.

Development activities – Activities following exploration including the installation of facilities and the drilling and completion of wells for production purposes.

Development well – A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well – A well found to be incapable of producing hydrocarbons economically.

EUR – Expected ultimate recovery from a well, reservoir or field.

Exploitation – The act of making oil and gas property more profitable, productive or useful.

Exploratory well – A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Farm-in or Farmout – An agreement where the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty and/or reversionary interest in the lease. The interest received by the assignee is a “farm-in” while the interest transferred by the assignor is a “farmout.”

FASB – The Financial Accounting Standards Board.

Field – An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

GAAP – Generally accepted accounting principles in the United States of America.

Gross acres or gross wells – The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling – A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques that may, depending on horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

Injection well – A well to inject gas, water, or liquefied petroleum gas under high pressure into a producing formation to maintain sufficient pressure to produce the recoverable reserves.

Mineral Rights - Ownership of minerals under a defined surface along with the legal right of access so the minerals can be extracted. Mineral rights can be separated and transferred from land ownership. Also called subsurface rights.

MBbls – One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE – One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

Mbtu (Mmbtu) – Used as a standard unit of measurement for natural gas and provides a convenient basis for comparing the energy content of various grades of natural gas and other fuels. One cubic foot of natural gas produces approximately 1,000 BTUs, so 1,000 cubic feet of gas is comparable to 1 MBTU. MBTU is often expressed as MMBTU, which is intended to represent a thousand BTUs.

Mcf – One thousand cubic feet.

Mcf/d – One thousand cubic feet per day.

Mcfe – One thousand cubic feet equivalent determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher for crude oil than natural gas on an energy equivalent basis although there have been periods in which they have been lower or substantially lower.

MMcf – One million cubic feet.

MMcf/d – One million cubic feet per day.

MMcfe – One million cubic feet equivalent.

Net acres or net wells – The product of the fractional working interests owned by gross acres or gross wells.

NGL’s – Natural gas liquids measured in barrels.

NRI or Net Revenue Interests – The share of production after satisfaction of all royalty, oil payments and other non-operating interests.

Normally pressured reservoirs – Reservoirs with a formation-fluid pressure equivalent to 0.465 PSI per foot of depth from the surface. For example, if the formation pressure is 4,650 PSI at a depth of 10,000 feet, the pressure is considered to be normal.

Over-pressured reservoirs – Reservoirs with a formation fluid pressure greater than 0.465 PSI per foot of depth from the surface.

Plant products – Liquids generated by a plant facility; including propane, iso-butane, normal butane, pentane and ethane.

Plugging and abandonment or P&A – Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

PV10% – The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with United States Securities and Exchange Commission guidelines, net of estimated lease operating expense, production taxes and future development costs, using prices, as prescribed in the United States Securities and Exchange Commission rules, and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion and amortization, or Federal income taxes and discounted using and annual discount rate of 10%. PV10% is considered a non-GAAP financial measure as defined by the United States Securities and Exchange Commission.

Possible reserves - are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. 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 faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the Company believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. Where direct observation has defined a highest known oil ("HKO") elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Primary recovery – The first stage of hydrocarbon production in which natural reservoir drives are used to recover hydrocarbons, although some form of artificial lift may be required to exploit declining reservoir drives.

Probable reserves - Are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Productive well – A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed nonproducing reserves or PDNP – Proved developed nonproducing reserves are proved reserves that are either shut-in or are behind-pipe reserves.

Proved developed producing reserves or PDP – Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.

Proved developed reserves – Proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) the area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) the project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved reserves – The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped location – A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUD – Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion – The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.

Re-engineering – A process involving a comprehensive review of the mechanical conditions associated with wells and equipment in producing fields. Our re-engineering practices typically result in a capital expenditure plan, which is implemented over time, to workover (see below) and re-complete wells and modify down-hole artificial lift equipment and surface equipment and facilities. The programs are designed specifically for individual fields to increase and maintain production, reduce down-time and mechanical failures, lower per-unit operating expenses, and therefore, improve field economics.

Reservoir – A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty – The portion of oil, gas, and minerals retained by the lessor on execution of a lease or their cash value paid by the lessee to the lessor or to one who has acquired possession of the royalty rights, based on a percentage of the gross production from the property free and clear of all costs except taxes.

Royalty interest – An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

SEC – The U.S. Securities and Exchange Commission.

Secondary recovery – The use of water-flooding or gas injection to maintain formation pressure during primary production and to reduce the rate of decline of the original reservoir drive.

Shut-in reserves – Those reserves expected to be recovered from completion intervals that were open at the time the reserve was estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or pipelines were not yet installed.

Standardized Measure of Discounted Future Net Cash Flows – Present value of proved reserves, as adjusted to give effect to estimated future abandonment costs, net of estimated salvage value of related equipment, and estimated future income taxes.

Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest or WI – The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and share of production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development operations and all risks in connection therewith.

Workover – Operations on a producing well to restore or increase production.

PART I

ITEM 1 – BUSINESS

Overview of Our Business

TransCoastal Corporation ("Company" or "TransCoastal") was incorporated in the State of Delaware in June 1999 in the original name of Claimsnet.com, Inc. ("Claimsnet") and has a fiscal year end of December 31.

We are an oil and gas exploration and production company focused primarily in the development of oil and gas reserves in the state of Texas. Our revenue comes from the sale of the hydrocarbons we produce and to a small extent from the trading of oil and gas properties. The Company has acquired or divested over 100 wells in Texas, and has over 200 undeveloped locations on over 6000 acres of leased oil and gas property located primarily in the panhandle area of west Texas. In addition to maintaining daily operations on our producing wells we also drill new wells, rehabilitate old wells and actively engage in locating additional oil and gas leases. A complete list of the oil and gas properties the Company currently owns or in which it has an interest is contained in the "Properties" section below.

History and Acquisitions

Prior to May 9, 2013 our business plan was to develop an electronic commerce company engaged in healthcare transaction processing for the medical and dental industries by means of the internet. On May 9, 2013 we acquired a majority interest in TransCoastal Corporation, a Texas corporation (“TransCoastal – Texas”) through an Amended Acquisitions Agreement. We issued a total of 3,721,036 shares of our Series F Preferred Stock (“Preferred Stock”), with an additional 194,920 shares of Preferred Stock to be issued as of June 30, 2013, in consideration for the common stock of TransCoastal – Texas. Each share of Preferred Stock issued has the attribute of having the voting right equal to 1,170.076 shares of common stock thereby giving the selling TransCoastal – Texas stockholders control of the corporation with the ability to vote 99.2% of all the votes eligible to vote for any matter brought before our equity holders. TransCoastal – Texas has one subsidiary, CoreTerra Operating LLC through which the primary oil and gas operations of TransCoastal are accomplished.

On May 9, 2013 the Company placed all of the assets and liabilities constituting the pre-acquisition non-oil and gas assets of our business operations into a separate wholly-owned subsidiary of the Company, ANC Holdings, Inc. (“ANC”). We determined that we could not make ANC profitable and that revenues from its operations would be insufficient to service its debt. On June 27, 2013 we sold ANC to certain debt holders of the Company in consideration for the debt holders assumption of the Company indebtedness owed to them. Once the sale of ANC was complete, the Company's sole business became oil and gas development and production.

Upon written consent of a majority of our stockholders we changed our name from Claimsnet to TransCoastal Corporation, instituted a 200 to 1 reverse stock split and increased our authorized shares from 110,000,000 to 275,000,000 with 250,000,000 shares being designated common and 25,000,000 designated as preferred stock by filing amendments to the Company's Certificate of Incorporation with the Delaware Secretary of State effective July 1, 2013.

Consistent with our view of the industry our primary focus is to acquire and operate additional producing oil and gas leases and wells, and acquire additional oil and gas prospect leases. In the past we have primarily acquired producing oil and gas properties with opportunities for future development and contracted well operations to contractors. Our new focus is a change in our business philosophy but one which we believe is better responsive to the oil and gas business opportunities available to us.

During 2011, we were able to acquire CoreTerra Operating, LLC a Texas limited liability company which is now a subsidiary of the Company. CoreTerra is located in Pampa, Texas and acts as our primary operator and properties manager for our oil and gas properties. Our operating company may from time to time, drill and act as a contact operator for third party wells. We receive fees both for the drilling of the well and once the well is completeted monthly fees for acting as the operator. We have found this beneficial not only from a revenue basis but also by expanding our knowledge base of different production fields. However as stated previously, we are currently concentrating on developing our own wells and therefore we are unlikely to recieve drilling fees in the near future. We do however continue to recieve some fees for those wells we do not own but act as a contract operator.

Since 2000, our efforts have focused primarily on the development of oil and gas reserves in Texas. The Company has acquired or divested over100 wells in this region, and has over 200 undeveloped locations on over 6000 acres of leased oil and gas property and additional leasing activities are on-going. A complete list of the oil and gas properties the Company currently owns or in which it has an interest is contained in the "Properties" section below.

While Liquid Natural Gas (LNG) may represent the future in natural gas the near term trend is for natural gas prices to stay low and are unlikely to climb above $5.50 per mcf in the near future. Consequently while the Company will continue to take advantage of values in assets located in gas producing areas our main focus, for the foreseeable future, will be to continue to acquire new assets and develop our current assets in those geographical locations which produce primarily crude oil. We believe that the price of crude oil which is currently priced at over $100 per bbl will continue close to that level for the next few years.

Business Strategy 

Our goal is to build long-term stockholder value by growing reserves and production revenues in a cost-efficient manner. To accomplish our goal, we plan to carry out a balanced program of (1) developing our multi-year inventory in the Brown Dolomite oil and gas properties near Pampa, Texas, and expand into other areas such as the Permian Basin and Wolfcamp oil shale play (2) operating as a low-cost producer, (3) pursuing strategic, complementary acquisitions and (4) maintaining financial flexibility. The following are key elements of our strategy:

●             Develop our properties. We believe we have a large inventory of drilling locations on our 1,252 undeveloped acres that provide us the ability to continue to increase production and reserves at a competitive cost. In addition the primary geological formation for our future development efforts, the Brown Dolomite, typically yields wells with a historical 40 year productive life. Consequently the Company will pursue development of their own properties rather than act as a contract driller/operator for third parties as we have done in the past. We plan to dedicate substantially all of our 2014 and 2015 exploration and development drilling budget to our current owned properties. Focusing on our regional approach allows us to develop operating, technical and regional expertise important to interpreting geological and operating trends, enhancing production rates and maximizing well recovery.

●             Operate our properties as a low-cost producer. We strive to minimize our operating costs by concentrating our assets within geographic areas where we can consolidate operating control and, thus, create operating efficiencies. We operate 100% of our reserve base and plan to continue to operate a substantial portion of our producing properties in the future. Operating control allows us to better manage timing and risk as well as the cost of exploration and development, drilling and ongoing operations.

●            Acquire strategic, complementary assets. TransCoastal targets the acquisition of mature assets in oil and gas fields which display long-lived, high-quality production, heavily weighted in oil and/or liquids rich natural gas production. We evaluate acquisitions based on decline profiles, reserve life and seek to take advantage of any operational in-efficiencies of the target operator. TransCoastal predominantly values the targets discounted cash flows from its proved developed producing category. TransCoastal requires the acquisition targets to have long term production histories with relatively predictable decline curves. Ideally, acquisition targets reserves remain largely underdeveloped and possess multiple Proved Un-developed (PUD) locations with what management believes are low-risk development opportunities. TransCoastal attempts to diminish the effects of potentially declining commodity prices by hedging up to 90% of its forecasted cash flows from operations. We do this in the form of swaps, collars or put options.

Development and Exploration Activities

Economic factors prevailing in the oil and gas industry change from time to time. The uncertain nature and trend of economic conditions and energy policy in the oil and gas business generally make flexibility of operating policies important in achieving desired profitability. We intend to evaluate continuously all conditions affecting our potential activities and to react to those conditions, as we deem appropriate from time to time by engaging in businesses we believe will be the most profitable for us. Given the current high price for crude oil and the lower price for natural gas we currently are concentrating our acquisitions in the Texas panhandle and other oil producing areas of Texas.

In addition, in order to finance future development and exploration activities, we will be seeking additional equity and debt funding and we may sponsor or manage public or private partnerships depending upon the number, size and economic feasibility of our generated prospects, the level of participation of industry partners and various other factors. However, potential investors should note that there can be no assurance that we will be able to enter into such financing arrangements or that if we are able to enter into such arrangements, we will be able to achieve any profitability as a result of our operations.

Subsidiaries

TransCoastal Corporation, a Texas corporation, is 99.6% owned by us. CoreTerra Operating LLC, a Texas limited liability company, a wholly-owned subsidiary of TransCoastal Corp. Texas, is a licensed and bonded oil and gas operator in Texas and is registered with the Texas Railroad Commission. CoreTerra Operating is responsible for drilling and maintaining production of all of TransCoastal’s oil and gas properties.

Healthexchange.net, a Delaware corporation, a wholly-owned subsidiary of the Company.

Significant Debt Instruments

Currently, the Company’s debt consists of a $17,500,000 loan with Greenbank, N.A. (“Greenbank”). The note is current and in compliance with Greenbank's requirements and covenants. The note matures June 1, 2015. Stuart G. Hagler, A.W. Westmoreland, and David J. May, are officers and directors of the Company and all three provide personal guarantees on our debt.

Governmental Regulations

Both state and federal authorities regulate the extraction, production, transportation, and sale of oil, gas, and minerals. The executive and legislative branches of government at both the state and federal levels have periodically proposed and considered proposals for establishment of controls on alternative fuels, energy conservation, environmental protection, taxation of crude oil imports, limitation of crude oil imports, as well as various other related programs. If any proposals relating to the above subjects were to be enacted, we cannot predict what effect, if any, implementation of such proposals would have upon our operations. A listing of the more significant current state and federal statutory authority for regulation of our current operations and business are provided below.

Federal Regulatory Controls

Historically, the transportation and sale of natural gas in interstate commerce have been regulated by the Natural Gas Act of 1938 (the ("NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and associated regulations by the Federal Energy Regulatory Commission ("FERC"). The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales." The FERC’s jurisdiction over natural gas transportation was unaffected by the Decontrol Act.

In 1992, the FERC issued regulations requiring interstate pipelines to provide transportation, separate or "unbundled," from the pipelines’ sales of gas (Order 636). This regulation fostered increased competition within all phases of the natural gas industry. In December 1992, the FERC issued Order 547, governing the issuance of blanket market sales certificates to all natural gas sellers other than interstate pipelines, and applying to non-first sales that remain subject to the FERC’s NGA jurisdiction. These orders have fostered a competitive market for natural gas by giving natural gas purchasers access to multiple supply sources at market-driven prices. Order No. 547 increased competition in markets in which we sell our natural gas.

Recently a new wave of legislation and regulation at the federal level has been initiated. Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Without limiting the generality of the foregoing, these laws and regulations may:

Our operations use hydraulic fracturing to drill new oil and gas wells. Hydraulic fracturing is a process that is used to release hydrocarbons, particularly natural gas, from certain geological formations. The process involves the injection of water (typically mixed with significant quantities of sand and small quantities of chemical additives) under pressure into the formation to fracture the surrounding rock and stimulate movement of hydrocarbons through the formation. The process is typically regulated by state oil and gas commissions and has been exempt (except when the fracturing fluids or propping agents contain diesel fuels) since 2005 from United States federal regulation pursuant to the Safe Drinking Water Act.

The EPA is conducting a comprehensive study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the United States House of Representatives is also conducting an investigation of hydraulic fracturing practices. The results of the EPA study and House investigation could lead to restrictions on hydraulic fracturing. The EPA is currently working on new guidance for application of the Safe Drinking Water Act permits for drilling or completing processes that use fracturing fluids or propping agents containing diesel fuels. In addition, the EPA proposed regulations under the federal Clean Air Act in July 2011 regarding certain criteria and hazardous air pollutant emissions from hydraulic fracturing wells and, in October 2011, announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other gas production.

Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing, including, for example, requiring disclosure of chemicals used in the fracturing process or seeking to repeal the exemption from the Safe Drinking Water Act. If adopted, such legislation would add an additional level of regulation and necessary permitting at the federal level and could make it more difficult to complete wells using hydraulic fracturing. Similar laws and regulations with respect to chemical disclosure also exist or are being considered by the United States Department of Interior and in several states, including certain states in which we operate, that could restrict hydraulic fracturing.

Future United States federal, state or local laws or regulations could significantly restrict, or increase costs associated with hydraulic fracturing and make it more difficult or costly for producers to conduct hydraulic fracturing operations, which could result in a decline of our exploration and production. New laws and regulations, and new enforcement policies by regulatory agencies, could also expressly restrict the quantities, sources and methods of water use and disposal in hydraulic fracturing and otherwise increase our costs and our customers’ cost of compliance, which could minimize water use and disposal needs even if other limits on drilling and completing new wells were not imposed. Any decline in exploration and production or any restrictions on water use and disposal could result in a decline in our drilling and rework activity and have a material adverse effect on our business, financial condition, results of operations and cash flows.

The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. The enactment of stricter legislation or the adoption of stricter regulation could have a significant impact on our operating costs, as well as on the oil and gas industry in general.

State Regulatory Controls

In each state where we conduct or contemplate oil and gas activities, these activities are subject to various regulations. The regulations relate to the extraction, production, transportation and sale of oil and natural gas, the issuance of drilling permits, the methods of developing new production, the spacing and operation of wells, the conservation of oil and natural gas reservoirs and other similar aspects of oil and gas operations. In particular, the State of Texas (where we have conducted our oil and gas operations to date) regulates the rate of daily production allowable from both oil and gas wells on a market demand or conservation basis. At the present time, no significant portion of our production has been curtailed due to reduced allowables. We know of no proposed regulation that will significantly impede our operations.

State Environmental Regulations

Our extraction, production and drilling operations are subject to environmental protection regulations established by federal, state, and local agencies. To the best of our knowledge, we believe that we are in compliance with the applicable environmental regulations established by the agencies with jurisdiction over our operations. We are acutely aware that the applicable environmental regulations currently in effect could have a material detrimental effect upon our earnings, capital expenditures, or prospects for profitability.

Our competitors are subject to the same regulations and therefore, the existence of such regulations does not appear to have any material effect upon our position with respect to our competitors. The Texas Legislature has mandated a regulatory program for the management of hazardous wastes generated during crude oil and natural gas exploration and production, gas processing, oil and gas waste reclamation and transportation operations. The disposal of these wastes, as governed by the Railroad Commission of Texas, is becoming an increasing burden on the industry.

As discussed above the likelihood of increased level of regulations at the federal level will also have a corresponding regulatory action at the state level.

Revenues from oil and gas production are subject to taxation by the state in which the production occurred. In Texas, the state receives a severance tax of 4.6% for oil production and 7.5% for gas production. These high percentage state taxes can have a significant impact upon the economic viability of marginal wells that we may produce and require plugging of wells sooner than would be necessary in a less arduous taxing environment.

Marketing and Transportation Regulations  

Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the Federal Energy Regulatory Commission ("FERC") that affect the economics of natural gas production, transportation and sales. In addition, FERC is continually proposing and implementing new rules affecting segments of the natural gas industry, most notably interstate natural gas transmission companies, which remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.

Our sales of crude oil and condensate are currently not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. However, we do not believe that these regulations affect us any differently than other crude oil producers.

Acquisition of Other Assets and Leveraging of Assets Acquired

The Company intends to acquire additional assets of a similar type and nature as the assets it currently has including new and existing hydrocarbon wells and oil and gas leases. In the event Company is unable to acquire the additional assets it plans to acquire it will take the Company significantly longer to implement profitable revenue producing activities. Any pro forma financial projections would then need to be adjusted to reflect the change in circumstances. If the Company should successfully acquire additional assets the assets may or may not be in the same geographical location as the assets we currently own as the Company reserves the right to acquire assets or operate in any geographic locations management believes, in their sole judgment, to be in the best interest of the Company.

Once the Company has acquired the oil and gas assets it intends to acquire, the Company may leverage those assets by borrowing from a financial source and using the assets as collateral. While this strategy will increase the available funds for Company use it will require the Company to pay debt service from its cash flow.

There can be no assurance that the Company will be able to achieve its objectives as its plans are dependent upon a number of factors including but not limited to the availability of additional debt and equity capital, the price it receives for it's oil and gas production, the performance of the economy, the availability of adequate materials, skilled employees and managers and the activities of our competition.

Management Employment Contracts

The Company reaffirmed previously existing employment agreements with Messrs. Westmorland, May, and Hagler as each is employed for a two-year term by the Company. A copy of these employment agreements are attached as exhibits to the 8-K filed with the SEC by the Company on June 14, 2013.

The Company has entered into employment agreements with its three executive officers. Currently Messer's. Hagler, Westmoreland and May receive a minimum of $10,000 per month in salary but may receive up to $50,000 per month if the cash flow and profitability of the Company will justify it. The contracts do not give any specific cash flow or profitability targets for any such increase and therefore are at the sole discretion of the Board of Directors of the company. In addition the aforementioned three executive officers also receive an annual stock grant which is also variable depending upon the amount of monthly salary they received during the fiscal year. If they receive an average of less than $25,000 per month in salary they each receive 200,000 shares of the common stock of the company. In the event each of the executives receives an average of more than $25,000 per month then the annual stock grants are 100,000 shares each. During the year 2012, the above three executive officers received payments from TransCoastal Partners (TCP), an affiliate of the Company, for their services in locating, developing, and completing certain wells for a third party. These are only summaries and do not purport to be the agreements in their entirety. To view the entire agreement please review the exhibits to the 8-K filed by the Company on June 14, 2013.

ITEM 1A - RISK FACTORS

Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K.

The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties, other than those we describe below, that are not presently known to us or that we currently believe are immaterial, may also impair our business operations. If any of the following risks occur, our business, financial condition and results of operations could be harmed.

RISKS RELATED TO OUR COMPANY

We do not intend to pay dividends on our common stock and, consequently, your only opportunity to achieve a return on your investment is if the price of our stock appreciates.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our notes purchase agreement places certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if the market price of our common stock appreciates, which may not occur, and you sell your shares at a profit. There is no assurance that the price of our common stock will ever exceed the price that you pay.

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities will dilute your ownership in us.

We may sell shares of common stock in public offerings or otherwise issue additional shares of common stock or convertible securities. We have filed a registration statement with the SEC on Form S-8 providing for the registration of 5,000,000 shares of our common stock reserved for issuance under our 2013 stock incentive plan which was approved by our stockholders. Subject to the satisfaction of vesting conditions and restrictions applicable to our affiliates under Rule 144 under the Securities Act shares registered under our registration statement on Form S-8 will be available for resale immediately in the public market without restriction. We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

We have a significant amount of debt that requires a significant amount of our cash flow to service as our assets are highly leveraged any default of our indebtedness could result in the loss of all or a significant portion of our producing assets.

We currently have long term liabilities in the form of bank debt in the amount of $17,500,000 which requires a monthly debt service payment of roughly $67,000 per month which uses a significant amount of our non-payroll cash and is secured by our producing well assets. Our monthly revenues, while currently sufficient to meet our debt service, do not provide adequate cash to allow us to grow our Company or provide a significant cushion in the event our revenues should decrease. Any default of our indebtedness could result in our creditors foreclosing on our producing well assets which would result in the Company seeking protection under the bankruptcy laws or ceasing as a going concern.

Our amended and restated certificate of incorporation and amended and restated bylaws and Delaware law contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to and desirable by our stockholders, including:

Furthermore, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the General Corporation Law of the State of Delaware, which prohibits, with some exceptions, stockholders owning in excess of 15% of our outstanding voting stock from engaging in business combination transactions with us.  

Our Board of Directors does not contain a majority of independent members and we do not have an Audit Committee. Good corporate governance practices call for the inclusion of independent members of our Board of Directors. Independent Board Directors act as a check on management and can assure that it acts in the best interests of all of our Company’s stakeholders. With our lack of independent Board members, we run a higher risk that our management could make subjective decisions without benefit of more measured independent guidance, rather than for the benefit of all of our shareholders. An independent Audit Committee qualitatively enhances a company’s internal controls over financial reporting. Among its functions, independent Audit Committees review the financial reporting, internal controls safeguarding Company assets, interact with auditors, may oversee material financial decisions and provide a sounding board for individuals who believe that there are irregularities in a Company’s accounting policies and procedures. With our lack of an Audit Committee at this time, we run a greater risk that a significant error or irregularity could occur that could be materially damaging to our shareholders.

RISKS RELATED TO OUR BUSINESS

Our exploration appraisal and development activities are subject to many risks which may affect our ability to profitably extract oil reserves or achieve targeted returns. In addition, continued growth requires that we acquire and successfully develop additional oil reserves.

Oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may negatively affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to negatively affect revenue and cash flow levels to varying degrees.

Our Future Success Depends Upon Our Ability To Find, Develop And Acquire Additional Oil And Gas Reserves That Are Economically Recoverable.

The rate of production from oil and natural gas properties declines as reserves are depleted. As a result, we must continually locate and develop or acquire new oil and gas reserves to replace those being depleted by production. We must do this even during periods of low oil and gas prices when it is difficult to raise the capital necessary to finance activities. Without successful exploration or acquisition activities, our reserves and revenues will decline. A future increase in our reserves will depend not only on our ability to explore and develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects. We cannot guaranty that we will be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, we may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations economically disadvantageous. We cannot guaranty that commercial quantities of oil will be discovered or acquired by us.

Oil and Gas Drilling Is A High-Risk Activity.

Our future success will depend on the success of our drilling programs. In addition to the numerous operating risks described in more detail below, these activities involve the risk that no commercially productive oil or gas reservoirs will be discovered. In addition, we are often uncertain as to the future cost or timing of drilling, completing and producing wells. Furthermore, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including, but not limited to, the following:

If we experience any of these problems, our ability to conduct operations could be adversely affected.

Factors Beyond Our Control Affect Our Ability To Market Oil And Gas.

Our ability to market oil and gas from our wells depends upon numerous factors beyond our control. These factors include, but are not limited to, the following:

If these factors were to change dramatically, our ability to market oil and gas or obtain favorable prices for our oil and gas could be adversely affected.

The Marketability Of Our Production May Be Dependent Upon Transportation Facilities Over Which We Have No Control.

The marketability of our production depends in part upon the availability, proximity, and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities could harm our business. We deliver some of our oil and natural gas through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future.

The Majority Of Our Sales Are With A Limited Number Of Purchasers. The majority of our hydrocarbon sales are to highly regulated, well capitalized entities.  The number of entities that can purchase our products are limited in the areas they can service due to significant capital, and regulatory requirements to enter the market.

For the years ended December 31, 2013 and 2012, revenues from the Company’s 44 and 33 producing leases, respectively, ranged from approximately 0.1% to 11.8% and 0.1% to 17.7%, respectively, of total oil, natural gas, and related product sales. These 44 and 33, respectively, leases are located in various counties of Texas.

For the years ended December 31, 2013 and 2012, the oil and natural gas produced by the Company is sold and marketed to 11 and 9 purchasers, respectively. Oil sales to three purchasers accounted for 95.5% of the oil sales for the year ended December 31, 2013. Individually, the three purchasers accounted for approximately 64.5%, 16.4%, and 14.6%. Oil sales to two purchasers accounted for 92.8% of the oil sales for the year ended December 31, 2012. Individually, the two purchasers accounted for approximately 71.1% and 21.7%. Natural gas sales to three purchasers account for 90.1% and 91.6%, respectively, of the natural gas sales. Individually, the three purchasers accounted for approximately 61.4%, 16.8% and 11.9% and 55.4%, 20.8%, and 15.4%, respectively. Accordingly, the Company’s entire oil and natural gas sales receivable balance at December 31, 2013 and 2012 was comprised of amounts due from its 11 and 9, respectively, purchasers. Oil and natural gas sales receivable are included in the accounts receivable, net on the accompanying consolidated balance sheets.

Third Party Credit Risk.  The Company is or may be exposed to third party credit risk through its contractual arrangements with its current or future marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures could have a material adverse effect on our cash flow from operations.

Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices could adversely affect our financial results.

Our future financial condition, results of operations and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and likely will continue to be volatile in the future, especially given world geopolitical conditions. Our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas. This price volatility also affects the amount of our cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow or have outstanding under or bank credit facility is subject to semiannual redeterminations. Oil prices are likely to affect us more than natural gas prices because approximately 70% of our proved reserves are oil. The prices for oil and natural gas are subject to a variety of additional factors that are beyond our control. These factors include:

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Also, oil and natural gas prices do not necessarily move in tandem. Declines in oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect upon our financial condition, results of operations, oil and natural gas reserves and the carrying values of our oil and natural gas properties. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations or make planned expenditures.

Significant capital expenditures are required to conduct our business.

The development of our business and operations, excluding acquisition activities, requires substantial capital expenditures. We will fund our capital expenditures through a combination of cash flows from operations and borrowings under our bank credit facilities and, to the extent those sources are not sufficient, we may fund capital expenditures from the proceeds of debt and equity issuances. Future cash flows from operations are subject to a number of risks and variables, such as the level of production of our customers, prices of natural gas and oil, and the other risk factors discussed herein. Our ability to obtain capital from other sources, such as the Markets, is dependent upon many of those same factors as well as the orderly functioning of credit and Markets. To the extent we fail to have adequate funds, we could be required to reduce our capital spending, or pursue other funding alternatives, which in turn could adversely affect our business and results of operations.

We Face Strong Competition From Other Energy Companies That May Negatively Affect Our Ability To Carry On Operations.

We operate in the highly competitive areas of oil and gas exploration, development and production. Factors that affect our ability to successfully compete in the marketplace include, but are not limited to, the following:

Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major interstate and intrastate pipelines and national and local gas gatherers. Many of these competitors possess greater financial and other resources than we do.

The inability to control other associated entities could adversely affect our business.

To the extent that we do not operate all of our properties, our success depends in part upon operations on certain properties in which we may have an interest along with other business entities. Because we have no control over such entities, we are able to neither direct their operations, nor ensure that their operations on our behalf will be completed in a timely and efficient manner. Any delay in such business entities’ operations could adversely affect our operations.

There Are Risks In Acquiring Producing Properties.

We constantly evaluate opportunities to acquire oil and natural gas properties and frequently engage in bidding and negotiating for these acquisitions. If successful in this process, we may alter or increase our capitalization through the issuance of additional debt or equity securities, the sale of production payments or other measures. Any change in capitalization affects our risk profile.

A change in capitalization, however, is not the only way acquisitions affect our risk profile. Acquisitions may alter the nature of our business. This could occur when the character of acquired properties is substantially different from our existing properties in terms of operating or geologic characteristics.

Operating Hazards May Adversely Affect Our Ability To Conduct Business.

Our operations are subject to risks inherent in the oil and gas industry, including but not limited to the following:

These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Governmental regulations may impose liability for pollution damage or result in the interruption or termination of operations.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

Although we intend to maintain several types of insurance to cover our operations, we may not be able to maintain adequate insurance in the future at rates we consider reasonable, or losses may exceed the maximum limits under our insurance policies. If a significant event that is not fully insured or indemnified occurs, it could materially affect our financial condition and results of operations.

Compliance with environmental and other government regulations could be costly and could negatively impact production.

Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Without limiting the generality of the foregoing, these laws and regulations may:

The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. The enactment of stricter legislation or the adoption of stricter regulation could have a significant impact on our operating costs, as well as on the oil and gas industry in general.

Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, but we do not believe that insurance coverage for environmental damages that occur over time or complete coverage for sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or may lose the privilege to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur.

Our operations are subject to United States federal, state and local laws and regulations relating to health, safety, transportation and protection of natural resources and the environment, including those relating to waste management and transportation and disposal of salt-water and other materials.

For example, we are subject to environmental regulation relating to the operation of our wells, which can pose some risks of environmental liability, including leakage from the wells to surface or subsurface soils, surface water or groundwater. Liability under these laws and regulations could result in cancellation of well operations, fines and penalties, expenditures for remediation, and liability for property damage and personal injuries.

Failure to comply with these laws and regulations could result in the assessment of significant administrative, civil or criminal penalties, imposition of cleanup and site restoration costs and liens, revocation of permits, and orders to limit or cease certain operations. In addition, certain environmental laws impose strict and/or joint and several liability, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time of those actions. Future events, such as the discovery of currently unknown matters, spills caused by future pipeline ruptures, changes in existing environmental laws and regulations or their interpretation, and more vigorous enforcement policies by regulatory agencies, may give rise to additional expenditures or liabilities, which could impair our operations and adversely affect our business and results of operations.

Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations.

Because our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies (such as wind, solar, geothermal, fuel cells and biofuels) that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse impact on our business, financial condition and results of operations. In addition, technological changes could decrease the quantities of water required for hydro-fracturing operations or otherwise affect demand for our services.

Increased regulation of hydraulic fracturing, including regulation of the quantities, sources and methods of water use and disposal, could result in reduction in drilling and completing new oil and natural gas wells or minimize water use or disposal, which could adversely impact the demand for our services.

Our Company success depends, in large part, on our level of exploration and production of oil and gas. Our operations use hydraulic fracturing to drill new oil and gas wells. Hydraulic fracturing is a process that is used to release hydrocarbons, particularly natural gas, from certain geological formations. The process involves the injection of water (typically mixed with significant quantities of sand and small quantities of chemical additives) under pressure into the formation to fracture the surrounding rock and stimulate movement of hydrocarbons through the formation. The process is typically regulated by state oil and gas commissions and has been exempt (except when the fracturing fluids or propping agents contain diesel fuels) since 2005 from United States federal regulation pursuant to the Safe Drinking Water Act.

The EPA is conducting a comprehensive study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the United States House of Representatives is also conducting an investigation of hydraulic fracturing practices. The results of the EPA study and House investigation could lead to restrictions on hydraulic fracturing. The EPA is currently working on new guidance for application of the Safe Drinking Water Act permits for drilling or completing processes that use fracturing fluids or propping agents containing diesel fuels. In addition, the EPA proposed regulations under the federal Clean Air Act in July 2011 regarding certain criteria and hazardous air pollutant emissions from hydraulic fracturing wells and, in October 2011, announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other gas production. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing, including, for example, requiring disclosure of chemicals used in the fracturing process or seeking to repeal the exemption from the Safe Drinking Water Act. If adopted, such legislation would add an additional level of regulation and necessary permitting at the federal level and could make it more difficult to complete wells using hydraulic fracturing. Similar laws and regulations with respect to chemical disclosure also exist or are being considered by the United States Department of Interior and in several states, including certain states in which we operate, that could restrict hydraulic fracturing.

Future United States federal, state or local laws or regulations could significantly restrict, or increase costs associated with hydraulic fracturing and make it more difficult or costly for producers to conduct hydraulic fracturing operations, which could result in a decline of our exploration and production. New laws and regulations, and new enforcement policies by regulatory agencies, could also expressly restrict the quantities, sources and methods of water use and disposal in hydraulic fracturing and otherwise increase our costs and our customers’ cost of compliance, which could minimize water use and disposal needs even if other limits on drilling and completing new wells were not imposed. Any decline in exploration and production or any restrictions on water use and disposal could result in a decline in our drilling and rework activity and have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our business is difficult to evaluate.

Our future financial results depend primarily on (1) our ability to discover commercial quantities of oil and gas; (2) the market price for oil and gas; (3) our ability to continue to generate potential exploration prospects; and (4) our ability to fully implement our exploration and development program. We cannot predict that our future operations will be profitable. In addition, our operating results may vary significantly during any financial period. These variations may be caused by significant periods of time between discovery and development of oil or gas reserves, if any, in commercial quantities.

Oil and natural gas prices are volatile and a decline in oil and natural gas prices can significantly affect our financial results and impede our growth.

The marketability of our oil and gas production depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, general economic conditions, changes in supply and changes in demand all could adversely affect our ability to produce and market our oil and natural gas. If market factors were to change dramatically, the financial impact could be substantial because we would incur expenses without receiving revenues from the sale of production. The availability of markets is beyond our control.

We may not discover commercially productive reserves.

Our future success depends on our ability to economically locate oil and gas reserves in commercial quantities. Except to the extent that we acquire properties containing proved reserves or that we conduct successful exploration and development activities, or both, our proved reserves, if any, will decline as reserves are produced. Our ability to locate reserves is dependent upon a number of factors, including our participation in multiple exploration projects and our technological capability to locate oil and gas in commercial quantities. We cannot predict that we will have the opportunity to participate in projects that economically produce commercial quantities of oil and gas in amounts necessary to create a positive cash flow for TransCoastal or that the projects in which we elect to participate will be successful. There can be no assurance that our planned projects will result in significant reserves or that we will have future success in drilling productive wells at economical reserve replacement costs.

Exploratory drilling is a high risk activity with many uncertainties that could adversely affect our business, financial condition or results of operations.

Exploratory drilling involves numerous risks, including the risk that we will not find any commercially productive oil or gas reservoirs. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including:

Our future drilling activities may not be successful, nor can we be sure that our overall drilling success rate or our drilling success rate for activities within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on our results of operations and financial condition. Also, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified a number of potential exploration projects, we cannot be sure that we will ever drill them or that we will produce oil or gas from them or any other potential exploration projects.

Our exploration and development activities are subject to reservoir and operational risks which may lead to increased costs and decreased production.

Even when oil and gas is found in what is believed to be commercial quantities, reservoir risks, which may be heightened in new discoveries, may lead to increased costs and decreased production. These risks include the inability to sustain deliverability at commercially productive levels as a result of decreased reservoir pressures, large amounts of water, or other factors that might be encountered. As a result of these types of risks, most lenders will not loan funds secured by reserves from newly discovered reservoirs, which would have a negative impact on our future liquidity. Operational risks include hazards such as fires, explosions, craterings, blowouts, uncontrollable flows of oil, gas or well fluids, pollution, releases of toxic gas and encountering formations with abnormal pressures. In addition, we may be liable for environmental damage caused by previous owners of property we own or lease. As a result, we may face substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur substantial losses. The occurrence of any one of these significant events, if it is not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Our operations require large amounts of capital and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves.

Our current development plans will require us to make large capital expenditures for the exploration and development of our oil and gas projects. Also, we must secure substantial capital to explore and develop our other potential projects. Historically, we have funded our capital expenditures through the issuance of equity and some debt. Volatility in the price of our Common Stock, which may be significantly influenced by our drilling and production activity, may impede our ability to raise money quickly, if at all, through the issuance of equity at acceptable prices. Future cash flows and the availability of financing will be subject to a number of variables, such as:

Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders.

If our revenues were to decrease due to lower oil and gas prices, decreased production or other reasons, and if we could not obtain capital through a credit facility or otherwise, our ability to execute our development plans, obtain and replace reserves, or maintain production levels could be greatly limited.

Oil and gas prices are volatile and an extended decline in prices could hurt our business prospects.

Our future profitability and rate of growth and the anticipated carrying value of our oil and gas properties will depend heavily on then prevailing market prices for oil and gas. We expect the markets for oil and gas to continue to be volatile. If we are successful in continuing to establish production, any substantial or extended decline in the price of oil or gas could:

Various factors beyond our control will affect prices of oil and gas, including:

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and gas. In addition, sales of oil and gas are seasonal in nature, leading to substantial differences in cash flow at various times throughout the year.

Oil and gas reserve estimates may not be accurate.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimates, and such revisions, if significant, would change the schedule of any further production and development drilling. Potential revisions due to an overstatement of the Company's oil and natural gas reserves, would also have adverse implications on our balance sheet and operating results, most specifically to the carrying value of our oil and natural gas properties and the results of our depletion expense. Accordingly, reserve estimates are generally different, and often materially so, from the quantities of oil and natural gas that are ultimately recovered. Furthermore, estimates of quantities of proved reserves and their PV-10 value may be affected by changes in crude oil and gas prices because the Company’s quantity estimates are based on prevailing prices at the time of their determination.

Hedging our production may result in losses.

We currently have limited hedging agreements in place. However, we may in the future enter into arrangements to further reduce our exposure to fluctuations in the market prices of oil and natural gas. We may enter into oil and gas hedging contracts in order to increase credit availability. Hedging will expose us to risk of financial loss in some circumstances, including if:

In addition, hedging may limit the benefit we would otherwise receive from increases in the prices of oil and gas. Further, if we do not engage in hedging, we may be more adversely affected by changes in oil and gas prices than our competitors who engage in hedging.

Accounting rules may require write-downs, which may result in a charge to earnings. We may incur write-downs of the net book values of our oil and natural gas properties that would adversely affect our equity and earnings.

We utilize the full cost method of accounting for costs related to our natural gas and oil properties. Under the full cost method, we are subject to quarterly calculations of a "ceiling" or limitation on the amount of our oil and gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and gas properties exceed the cost center ceiling, we are subject to a write-down of our net oil and gas properties to the extent of such excess. A capitalized cost ceiling test impairment also reduces earnings and impacts stockholders' equity in the period of occurrence and results in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments.

The risk that we will be required to write down the carrying value of oil and natural gas properties increases when natural gas and crude oil prices are depressed or volatile. In addition, a write-down of proved oil and natural gas properties may occur if we experience substantial downward adjustments in our estimated proved reserves, or if purchasers cancel long-term contracts for our natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the applicable ceiling in the subsequent period. This and other factors could cause us to write down our natural gas and oil properties or other assets in the future and incur a non-cash charge against future earnings.

We face risks related to title to the leases we enter into that may result in additional costs and affect our operating results.

It is customary in the oil and gas industry to acquire a leasehold interest in a property based upon a preliminary title investigation. If the title to the leases acquired is defective, we could lose the money already spent on acquisition, or incur substantial costs to cure the title defect, including any necessary litigation. If a title defect cannot be cured, we will not have the right to participate in the development of or production from the leased properties. In addition, it is possible that the terms of our oil and gas leases may be interpreted differently depending on the state in which the property is located. For instance, royalty calculations can be substantially different from state to state, depending on each state’s interpretation of lease language concerning the costs of production. We cannot guarantee that there will be no litigation concerning the proper interpretation of the terms of our leases. Adverse decisions in any litigation of this kind could result in material costs or the loss of one or more leases.

Our leases primary terms may expire prior to drilling.

Oil and gas leases have a primary term in which drilling or operations must commence; otherwise, the lease will expire. As such, we may have insufficient capital to drill leases or economic conditions may change which make the leases not commercially viable or equipment and man power may not be available to drill during the primary term. If any of this occurs, we will have to write the value of the leases off in the current earnings period in which they expire.

Our industry is highly competitive and many of our competitors have more resources than we do.

We compete in oil and gas exploration with a number of other companies. Many of these competitors have financial and technological resources vastly exceeding those available to us. We cannot be sure that we will be successful in acquiring and developing profitable properties in the face of this competition. In addition, from time to time, there may be competition for, and shortage of, exploration, drilling and production equipment. These shortages could lead to an increase in costs and delays in operations that could have a material adverse effect on our business and our ability to develop our properties. Problems of this nature also could prevent us from producing any oil and gas we discover at the rate we desire to do so.

Technological changes could put us at a competitive disadvantage.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As new technologies develop, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at a substantial cost. If other oil and gas exploration and development companies implement new technologies before we do, those companies may be able to provide enhanced capabilities and superior quality compared with what we are able to provide. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If we are unable to utilize the most advanced commercially available technologies, our business could be materially and adversely affected.

Our industry is heavily regulated and increases the costs of our operations.

Federal, state and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of oil and gas production. State and local authorities regulate various aspects of oil and gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of oil and gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and drill site restoration. The overall regulatory burden on the industry increases the cost of doing business, which, in turn, decreases profitability.

Our operations must comply with complex environmental regulations.

Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities. New laws or regulations, or changes to current requirements, could have a material adverse effect on our business. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. We could face significant liabilities to the government and third parties for discharges of oil, natural gas, produced water or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation. We cannot be sure that existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced or altered in the future, will not have a material adverse effect on our results of operations and financial condition.

Our business depends on transportation facilities owned by others.

The marketability of our potential oil and gas production depends in part on the availability, proximity and capacity of pipeline systems owned or operated by third parties. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Attempts to grow our business could have an adverse effect.

Because of our small size, we desire to grow rapidly in order to achieve certain economies of scale. Although there is no assurance that this rapid growth will occur, to the extent that it does occur, it will place a significant strain on our financial, technical, operational and administrative resources. As we increase our services and enlarge the number of projects we are evaluating or in which we are participating, there will be additional demands on our financial, technical and administrative resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations.

RISKS RELATED TO OUR EQUITY STOCK

Our directors and officers of the Company own a significant majority of our common stock and the ability of other stockholders to influence the Company and its affairs is limited.

Three of our executive officers and directors control approximately 75% of our issued and outstanding shares of our voting Common Stock. They therefore have the current ability to control the affairs of the Company and to determine the path our Company will take. All other Common Stock stockholders will not have sufficient voting power to override or otherwise influence any vote taken by the stockholders of the Company.

Our Common Stock may continue to be subject to penny stock regulation.

Our Common Stock is presently subject to additional disclosure requirements for penny stocks mandated by the Penny Stock Reform Act of 1990. The SEC Regulations generally define a penny stock to be an equity security that is not traded on a national exchange and has a market price of less than $5.00 per share. Depending upon our stock price, we may be included within the SEC Rule 3a51-1 definition of a penny stock and have our Common Stock considered to be a "penny stock," with trading of our Common Stock covered by Rule 15g-9 promulgated under the Securities Exchange Act of 1934. Under this rule, broker-dealers who recommend such securities to persons other than established customers and accredited investors must make a special written disclosure to, and suitability determination for, the purchaser and receive the purchaser’s written agreement to a transaction prior to sale. The regulations on penny stocks limit the ability of broker-dealers to sell our Common Stock and thus may also limit the ability of purchasers of our Common Stock to sell their securities in the secondary market. Our Common Stock will not be considered "penny stock" if our net tangible assets exceed $2,000,000 or our average revenue is at least $6,000,000 for the previous three years.

The Financial Industry Regulatory Authority sales practice requirements may also limit a stockholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, the Financial Industry Regulatory Authority or FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low-priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for shares of our common stock.

Our Common Stock could be subject to a disproportionately high number of sales, which could cause the market price of our Common Stock to drop significantly, even if our business is doing well.

A disproportionately high number of sales might occur because of the long period of time during which investors have not been able to sell any portion of their investment in the Company. If there were a large number of shares sold, it could result in significant downward pressure on the market price for our Common Stock.

Trading of our common stock may be volatile and sporadic, which could depress the market price of our common stock and make it difficult for our stockholders to resell their shares.

There is currently a limited market for our common stock and the volume of our common stock traded on any day may vary significantly from one period to another. Our common stock is quoted on OTC Market’s OTCQB. Trading in stock quoted on OTC Market’s OTCQB is often thin and characterized by wide fluctuations in trading prices, due to many factors that may have little to do with our operations or business prospects. The availability of buyers and sellers represented by this volatility could lead to a market price for our common stock that is unrelated to operating performance. Moreover, OTC Market’s OTCQB is not a stock exchange, and trading of securities quoted on OTC Market’s OTCQB is often more sporadic than the trading of securities listed on a stock exchange like NASDAQ. There is no assurance that a sufficient market will develop in the stock, in which case it could be difficult for our stockholders to resell their stock.

Raising additional capital and acquiring additional companies may substantially dilute existing shareholders.

Our intention is to grow the Company significantly which will require us to issue additional common stock should we raise additional capital through both public and private offerings. We may also issue additional common stock in the acquisition of or merger with other companies we may acquire. The effect of both these activities would result in the significant dilution of the Company’s current stockholders.

Our Board of Directors can issue preferred stock with terms that are preferential to our common stock.

Pursuant to our articles of incorporation, as amended, our Board of Directors may issue additional preferred stock without action by our stockholders, with in such series and classes, and with rights and preferences related thereto, determined by the Board of Directors. Rights or preferences could include, among other things:

We make estimates and assumptions in connection with the preparation of TransCoastal’s Condensed Consolidated Financial Statements, and any changes to those estimates and assumptions could have a material adverse effect on our results of operations.

In connection with the preparation of TransCoastal’s Condensed Consolidated Financial Statements, we use certain estimates and assumptions based on historical experience and other factors. Our most critical accounting estimates are described in "Management Discussion and Analysis of Financial Condition and Results of Operations" in this report. In addition, as discussed in Note 4 to the Consolidated Financial Statements, we make certain estimates, including decisions related to provisions for legal proceedings and other contingencies. While we believe that these estimates and assumptions are reasonable under the circumstances, they are subject to significant uncertainties, some of which are beyond our control. Should any of these estimates and assumptions change or prove to have been incorrect, it could have a material adverse effect on our results of operations.

Failure of the Company’s internal control over financial reporting could harm its business and financial results.

ITEM 1B - UNRESOLVED STAFF COMMENTS.

In the process of filling and S1 Registration Statement with the SEC

The Company is currently in the process of filing an S-1 Registration Statement with the SEC and has responded to the staff's comment letter dated April 3, 2014. 

Item II. Properties

Operations

Oil and Gas Leases and Wells

The Company’s 23 Oil and Gas lease properties consist of approximately 7,310 gross/ 6,065 net acres, which are primarily held by production. The Properties comprise approximately 66 producing wells generating net production of approximately 73 bbls/day and 370 mcf/day during fiscal year 2013. Cash flow used in operations for TransCoastal for the twelve months ending 12/31/13 was approximately $1.7 million. The majority of the Company’s asset base is comprised of long life Panhandle hydrocarbon production in wells that all produce oil, natural gas liquids and natural gas. The following is a table showing our developed and undeveloped lease acreage followed by a list and legal description of our oil and gas leases located in the state of Texas and Louisiana.      

Developed and Undeveloped Acreage

Lease Name and Location of TransCoastal Oil and Gas Leases

The Company currently receives production from 66 wells located on the above leases. Of the 66 wells it operates 63 of the wells through its operating subsidiary CoreTerra. The remaining three wells are operated by unrelated third party operators. The following is a listing of our wells, the lease location and the field name:

From the above wells the Company receives certain hydrocarbon production in the form of oil, natural gas and condensates which it markets to third party purchasers. The following chart lists our net production, total sales and average price we experienced from our wells in the last two fiscal years:

As part of our ongoing business we continue to develop the potential of our existing leases primarily through the drilling of new wells. The following table displays our development costs for the last two fiscal years:

Oil and Natural Gas Reserves

Controls Over Reserve Report Preparation

Our long term prospects for continuing to extract oil and gas are directly related to our oil and gas reserves. Estimates of proved reserves at December 31, 2013, were prepared by PeTech Enterprises, Inc., independent petroleum consultants, a Texas registered engineering firm. The technical person responsible for preparing the reserve estimates is an independent petroleum engineer and geoscientist that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Specifically, our reserve report was prepared by Mr. Amiel David PhD, a Texas registered petroleum engineer with over 40 years of field experience. Mr. David has a Doctorate from Stanford University in Petroleum Engineering, an MBA from the University of Pittsburgh, an MSE in Chemical Engineering from the University of Pennsylvania and a Bachelor's of Science Degree in Petroleum Engineering from the University of Tulsa. The reserve report is then reviewed and approved by our in-house petroleum engineers and geoscientists.

The reserve report was prepared as of December 31, 2013, under United States Securities and Exchange Commission pricing requirements. The 2013 reserve report summary is an exhibit to this report.

The following table is a tabular representation of the estimate for our proved developed and undeveloped reserves:

Marketing

Our ability to market oil and natural gas often depends on factors beyond our control. The potential effects of governmental regulation and market factors, including alternative domestic and imported energy sources, available pipeline capacity, and general market conditions, are not entirely predictable.

Natural gas is generally sold pursuant to individually negotiated gas purchase contracts, which vary in length from spot market sales of a single day to term agreements that may extend several years. Customers who purchase natural gas include marketing affiliates of the major oil and gas companies, pipeline companies, natural gas marketing companies, and a variety of commercial and public authorities, industrial, and institutional end-users who ultimately consume the gas. Gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market may vary daily, reflecting changing market conditions. The deliverability and price of natural gas are subject to both governmental regulation and supply and demand forces.

The Company sells natural gas to one of three customers, Eagle Rock Energy Partners, DCP Midstream, LLC, and Valero. All three customers are well capitalized and regulated. The Company does not anticipate any customer becoming unable to perform under their agreement.

Oil produced is sold at the prevailing field price to one or more of a number of unaffiliated purchasers in the area. Generally, purchase contracts for the sale of oil are cancelable on 30 days’ notice. The price paid by these purchasers is an established market or "posted" price that is offered to all producers.

Competition

We compete with major integrated oil and natural gas companies and independent oil and natural gas companies in all areas of our operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Many of our competitors have substantially greater financial and other resources than we have. Larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. Our competitors also may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have operated for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

At various times we may experience occasional or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and natural gas drilling. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and natural gas leases to lapse.

Title to Properties

In most situations, as is customary in the oil and gas industry, only a preliminary title examination is conducted at the time we acquire oil and gas leases covering properties for possible drilling operations. Prior to the commencement of drilling operations, a more complete title examination of the drill site tract is usually conducted by independent attorneys or landmen. Once production from a given well is established, we prepare a division order title report indicating the proper parties and percentages for payment of production proceeds, including royalties. The level of title examination often differs from property to property. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect the carrying value of our properties.

Company Offices

The Company currently leases office space in Dominion Plaza, 17304 Preston Road, Suite 700, Dallas, Texas 75252. The Company entered into a Lease Agreement on April 28, 2008, to lease 8,153 square feet of office space in Dallas, Texas for a term of 78 months and expiring on December 1, 2014. The Company pays monthly rent of $14,264.75 and utilities of approximately $1,494.72. The base monthly rent increases each year with a base monthly rent of $14,607.46 in 2013 and $14,947.17 in 2014.

In November 2009, the Company purchased office; garage and yard space located at 2601 W. Kentucky, Pampa, Texas 79065. This property consists of an acre of land and a free-standing single story building that is approximately 10,000 square feet in size.  

Employees

The Company headquarters and its subsidiary employ twenty-one (21) full-time employees. The employees are assigned to the following departments: administrative, accounting, and operations.

Available Information

We file annual, quarterly and current reports, proxy statements and other information electronically with the United States Securities and Exchange Commission (“SEC”). You may read and copy any materials we file with the United States Securities and Exchange Commission at the United States Securities and Exchange Commission’s Public Reference Room at 100 F. Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the United States Securities and Exchange Commission at 1-800-SEC-0330. The United States Securities and Exchange Commission maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the United States Securities and Exchange Commission, including our filings.

Our internet address is www.transcoastal.net. We make available free of charge on or through our internet site our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the United States Securities and Exchange Commission.

ITEM 3 - LEGAL PROCEEDINGS

The Company is involved in various legal proceedings, including the proceedings specifically discussed below. Management of the Company believes that any liability not listed below that may arise as a result of these proceedings will not have a material adverse effect on the financial condition of the Company and its subsidiaries taken as a whole unless otherwise noted.

In 2013, litigation began between a subsidiary of the Company and a third party. The Company was the defendant in the litigation pertaining to wells drilled for the third party and the lack of support for charges assessed during drilling. The litigation was settled in December of 2013. Chief amongst the details of the settlement were that the monetary issues were to be settled during arbitration in March 2014. The arbitration hearing was had and it was decided the Company must pay an award of $580,000 to the plaintiff party. This litigation has an adverse material effect on the financials of the Company as the “loss on turnkey contracts” disclosed within the financial statements are a result of this litigation.

ITEM 4 - MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Market information

Our common stock is quoted on OTCQB under the symbol “TCEC.”

The following table shows the quarterly range of high and low bid information for our common stock over the fiscal quarters for the last two fiscal years as quoted on OTCQB. We obtained the following high and low bid information from OTCQB. These over-the-counter market quotations reflect inter-dealer prices without retail mark-up, mark-down or commission, and may not represent actual transactions. Investors should not rely on historical prices of our common stock as an indication of its future price performance. On March 31, 2014, the closing price of our common stock as reported by OTCQB was $1.75 per share and is reflective of the effect of our 200 for one reverse split which took effect July 1, 2013.

As of December 31, 2013, there were an estimated 401 holders of record of our common stock, exclusive of objecting beneficial owners (individuals who deposit shares with a broker and don’t wish to provide to the Company personal information).

Dividends

To date, we have not paid any dividends on our common stock nor established a policy concerning payment of Common Stock dividends. Any payment of dividends in the future will be determined by the Board of Directors in light of conditions then existing, including restrictions imposed by our preferred stock then outstanding, if any, our earnings, financial condition, capital requirements and debt covenants, if any, and the tax treatment of any such dividends. 

Unregistered Sales of Equity

Exemption from Registration Claimed

The initial issuance of the Preferred Shares described above were issued by us in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, provided by Sections 4(2) and 4(5) in that all participants were Accredited Investors as that term is defined in Rule 501 Regulation D. All of the individuals and/or entities listed above that purchased the unregistered securities were all known to us and our management, through pre-existing business relationships, as long standing business associates, friends, and employees. All purchasers were provided access to all material information, which they requested, and all information necessary to verify such information and were afforded access to our management in connection with their purchases. All purchasers of the unregistered securities acquired such securities for investment and not with a view toward distribution, acknowledging such intent to us. All certificates or agreements representing such securities that were issued contained restrictive legends, prohibiting further transfer of the certificates or agreements representing such securities, without such securities either being first registered or otherwise exempt from registration in any further resale or disposition.

ITEM 6 – SELECTED FINANCIAL DATA

Not Applicable

ITEM 7 – MANAGEMENT DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONAND RESULTS OF OPERATIONS

 MANAGEMENT DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with our audited consolidated financial statements and notes thereto for the fiscal years ended December 31, 2013 and 2012, included elsewhere in this report. The following Management Discussion and Analysis of Financial Condition and Results of Operations contains “forward-looking statements”. Forward-looking statements are generally written in the future tense and/or are preceded by words such as “may,” “should,” “forecast,” “could,” “expect,” “suggest,” “believe,” “anticipate,” “intend,” “plan,” or other similar words. The forward-looking statements contained in this report involve a number of risks and uncertainties, many of which are outside of our control. Factors that could cause actual results to differ materially from projected results include, but are not limited to, those discussed in “Risk Factors” elsewhere in this report. Although we believe that the assumptions underlying the forward-looking statements contained in this report are reasonable, any of the assumptions could be inaccurate, and therefore there can be no assurance that such statements will be accurate. In light of the significant uncertainties inherent in the forward-looking statements included herein, the inclusion of such information should not be regarded as a representation by us or any other person that the results or conditions described in such statements or our objectives and plans will be achieved. Furthermore, past performance in operations and share price is not necessarily indicative of future performance. Except as required by applicable laws including the securities laws of the United States, we disclaim any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Our Business

We are an oil and gas exploration and production company. We acquire oil and gas leases from landowners in geographical locations which we believe have the potential for the successful drilling of new wells to locate commercial quantities of oil and gas or which have existing wells which we believe can be rehabilitated or stimulated to produce additional quantities of hydrocarbons. Once the wells are drilled or acquired we operate the wells to manage their production and market the oil and gas produced. We also receive fees to operate wells not owned by us.

RESULTS OF OPERATIONS

For the year ended December 31, 2013 compared to year ended December 31, 2012:

During the year ended December 31, 2013, production decreased 307 barrels of oil as compared to 26,413 sold in 2012.  During the year ended December 31, 2013, we produced an additional 17,734 MCFs of gas as compared to 134,736 sold in 2012.  Our average price per barrel sold during 2013 increased by $2.95 from the $90.86 in 2012. Our average price per MCF (adjusted for liquids content) sold during 2013 decreased by $1.12 from the $9.51 in 2012.  These items increased our revenues from oil in 2013 by $49,000 and decreased our revenues from gas in 2013 by $3,000.

Revenue. During the year ended December 31, 2013 the Company generated revenues of $3,622,000, a decrease of $2,886,000 or 44% as compared to the same period last year. The Company had decreased revenues through drilling services to third parties. The Company has determined to pursue development of their own assets rather than to drill and complete other parties properties resulting in the drastic decline in total revenues.

During the year ended December 31, 2013 the Company generated revenues from oil and gas sales of $3,728,000 an increase of $46,000 or 1% as compared to the same period last year. The Company had no revenues through drilling services to third parties generating a decrease of $2,746,000. The Company has determined to pursue development of their own assets rather than to drill and complete other parties properties.

Total Expenses. During the year ended December 31, 2013, total expenses, which are comprised of depreciation, operating costs and general and administrative expenses, were $7,025,000 compared to $4,717,000 during the same period in 2012. This change represents an increase of $2,308,000 or 49%. The increase is primarily due to increased professional and legal fees as a result of ongoing litigation and the costs of becoming a public entity. The company also incurred losses on turn key contracts in 2013 as a result of drilling done for a third party in 2012.

Summary of Cash Flows. Net cash used in operating activities of ($1,654,000) for the twelve months ended December 31, 2013 decreased from cash provided by operations of $1,571,000 during the same period in 2012. This change represents a decrease of $3,225,000. The decrease is primarily due to the decrease in net income of 4,944,000 due to the lack of income from third party drilling and increased expenses as a result of ongoing litigation and the costs of becoming a public entity.