Amended Annual Report (10-k/a)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10K/A

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

For the fiscal year ended December 31, 2013

☐ 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)

Delaware	75-2649230
State or other jurisdiction of	I.R.S. Employer
incorporation or organization	Identification No.

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:

Title of each class		Name of each exchange on which registered
Common stock		OTC

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).

Large accelerated filer ☐	Accelerated filer	☐
Non-accelerated filer ☐	Smaller reporting company	☒

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

		Page
PART I

ITEM 1	Business	4
ITEM 1A	Risk Factors	8
ITEM 1B	Unresolved Staff Comments	20
ITEM 2	Properties	20
ITEM 3	Legal Proceedings	28
ITEM 4	Mine Safety Disclosures	28

PART II

ITEM 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
ITEM 6	Selected Financial Data	30
ITEM 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	30
ITEM 7A	Quantitative and Qualitative Disclosures About Market Risk
ITEM 8	Financial Statements and Supplementary Data	F-2
ITEM 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	32
ITEM 9A	Controls and Procedures	33
ITEM 9B	Other Information	34

PART III (incorporated by reference to be filed with the Company’s Definitive Proxy Statement)

ITEM 10	Directors, Executive Officers, and Corporate Governance	34
ITEM 11	Executive Compensation	36
ITEM 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	36
ITEM 13	Certain Relationships and Related Transactions, and Director Independence	37
ITEM 14	Principal Accounting Fees and Services	37

PART IV

ITEM 15	Exhibits, Financial Statement Schedules	38

SIGNATURES		39

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:

	•		changes in production volumes, worldwide demand and commodity prices for oil and natural gas;
	•		changes in estimates of proved reserves;
	•		declines in the values of our oil and natural gas properties resulting in impairments;
	•		the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves;
	•		our ability to acquire leases, drilling rigs, supplies and services on a timely basis and at reasonable prices;
	•		risks incident to the drilling and operation of oil and natural gas wells;
	•		future unanticipated production and development costs;
	•		the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on prices or costs;
	•		the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America and its individual states;
	•		changes in environmental laws and the regulation and enforcement related to those laws;
	•		the identification of and severity of environmental events and governmental responses to the events;
	•		legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, derivatives reform, and changes in state, federal and foreign income taxes;
	•		the effect of oil and natural gas derivatives activities; and
	•		conditions in the capital markets.

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 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 Holdings, Inc. 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.

Within the last year 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.

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:

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require the acquisition of a permit before drilling commences;

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restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;

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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas;

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require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and

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impose substantial liabilities for pollution resulting from our operations.

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.

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 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 which 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:

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a classified board of directors, so that only approximately one-third of our directors are elected each year;

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limitations on the removal of directors;

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limitations on the ability of our stockholders to call special meetings; and

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advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

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. See "Description of Capital Stock—Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Delaware Law."

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:

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unexpected drilling conditions;

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pressure or irregularities in formations;

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equipment failures or accidents;

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adverse weather conditions;

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inability to comply with governmental requirements; and

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shortage or delays in the availability of drilling rigs and the delivery of equipment.

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:

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the level of domestic production and imports of oil and gas;

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the proximity of gas production to gas pipelines;

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the availability of pipeline capacity;

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the demand for oil and gas by utilities and other end users;

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the availability of alternate fuel sources;

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the effect of inclement weather;

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state and federal regulation of oil and gas marketing; and

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federal regulation of gas sold or transported in interstate commerce.

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:

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the level of consumer demand for oil and natural gas;

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the domestic and foreign supply of oil and natural gas;

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the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

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the price of foreign oil and natural gas;

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domestic governmental regulations and taxes;

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the price and availability of alternative fuel sources;

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weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico;

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market uncertainty;

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political conditions in oil and natural gas producing regions, including the Middle East; and

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worldwide economic conditions.

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:

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the availability of funds and information relating to a property;

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the standards established by us for the minimum projected return on investment;

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the availability of alternate fuel sources; and

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the intermediate transportation of gas.

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:

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blowouts;

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cratering;

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explosions;

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uncontrollable flows of oil, gas or well fluids;

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fires;

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pollution; and

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other environmental risks.

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.

L osses 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:

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require the acquisition of a permit before drilling commences;

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restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;

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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas;

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require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and

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impose substantial liabilities for pollution resulting from our operations.

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.

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:

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unexpected drilling conditions,

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pressure or irregularities in formations,

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equipment failures or accidents,

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adverse weather conditions,

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compliance with governmental requirements,

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shortages or delays in the availability of drilling rigs and the delivery of equipment, and

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shortages of trained oilfield service personnel.

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:

●

our success in locating and producing reserves in other projects;

●

the level of production from existing wells; and

●

prices of oil and gas.

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

●

our being more vulnerable to competitive pressures and economic downturns; and

●

restrictions on our operations.

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:

●

have a material adverse effect on our results of operations;

●

limit our ability to attract capital;

●

make the formations we are targeting significantly less economically attractive;

●

reduce our cash flow and borrowing capacity; and

●

reduce the value and the amount of any future reserves.

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

●

worldwide and domestic supplies of oil and gas;

●

the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

●

political instability or armed conflict in oil or gas producing regions;

●

the price and level of foreign imports;

●

worldwide economic conditions;

●

marketability of production;

●

the level of consumer demand;

●

the price, availability and acceptance of alternative fuels;

●

the availability of processing and pipeline capacity;

●

weather conditions; and

●

actions of federal, state, local and foreign authorities.

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:

●

production is less than expected;

●

the other party to the contract defaults on its obligations; or

●

there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

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:

●

the establishment of dividends which must be paid prior to declaring or paying dividends or other distributions to our common stockholders;

●

greater or preferential liquidation rights which could negatively affect the rights of common stockholders; and

●

the right to convert the preferred stock at a rate or price which would have a dilutive effect on the outstanding shares of Common Stock.

As of March 31, 2014 our Board of Directors has approved the sale of two different series of Preferred Stock: Series G and Series H. For the attributes of these preferred series please see the “Description of Securities” section within this Registration Statement.

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’s Discussion and Analysis of Financial Condition and Results of Operations" in this report. In addition, as discussed in Note 2 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.

The management of TransCoastal is responsible for establishing and maintaining effective internal control over financial reporting. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes maintaining records that in reasonable detail accurately and fairly reflect the Company’s transactions; providing reasonable assurance that transactions are recorded as necessary for preparation of the financial statements; providing reasonable assurance that receipts and expenditures are made in accordance with management authorization; and providing reasonable assurance that unauthorized acquisition, use or disposition of the Company assets that could have a material effect on the financial statements would be prevented or detected on a timely basis. Because of its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of the Company’s financial statements would be prevented or detected. Failure to maintain an effective system of internal control over financial reporting could limit the Company’s ability to report its financial results accurately and timely or to detect and prevent fraud. In addition, a restatement of the Company’s oil and natural gas reserves may also have adverse implications on the Company’s carrying value of its oil and natural gas properties, depletion calculation and standard measures of oil and gas disclosures.

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

Developed Acres

Undeveloped Acres

Gross

Net

Gross

Net

Total:

7,310

6,065

1,422

978

Lease Name and Location of TransCoastal Oil and Gas Leases

Lease	County	Abstract	Survey	Block	Section
Bell	Gray	447	I. & G.N. RR	3	134
Brown	Gray	447	I. & G.N. RR	3	152, 137, 128, 138
Brown "A"	Gray	447	I. & G.N. RR	3	152, 137, 128, 138
Crow	Gray	447	I. & G.N. RR	3	152, 137, 128, 138
Faith	Gray	447	I. & G.N. RR	3	135
Jackson	Gray	447	I. & G.N. RR	3	152, 137, 128, 138
Jackson "A"	Gray	447	I. & G.N. RR	3	152, 137, 128, 138
Heitholt	Gray	447	I. & G.N. RR	3	152, 137, 128, 138
Cobb	Gray	447	I. & G.N. RR	3	164, 165, 141, 148
Heaston	Gray	447	I. & G.N. RR	3	164, 165, 141, 148
Leopold B,C,A	Gray	447	I. & G.N. RR	3	164, 165, 141, 148
Skoag	Gray	447	I. & G.N. RR	3	164, 165, 141, 148
Skoag A	Gray	447	I. & G.N. RR	3	164, 165, 141, 148
MPS Ellenburger	Montague	247	ET RR, CO
Pugh	Stephens	630, 565, 1592, 330	T&P RR CO	5	4, 1338, 1337, 11
Savell	Shelby	385	R. Jarvis
Mayfield B&C	Hutchinson		D&P RR CO	R	2, 5
Meers	Gray		I. & G.N. RR	3	107
Stevenson A	Hutchinson		D&P RR CO	R	2, 5
Gene Borders	Shelby		Holt, M S
Bill Phillips	Hutchinson		TC RR CO	M-24	8
TJ Boney	Carson		I. & G.N. RR	4	110
Couba DuLarge	St. Charles (LA)		I. & G.N. RR	T-19S	36

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:

TYPE OF RESERVE	LEASE/WELL NAME	FIELD
Proved Producing	Stevenson 'A' - #2	Panhandle Hutchinson County Fld.
Proved Producing	Stevenson 'A' - #4	Panhandle Hutchinson County Fld.
Proved Producing	Stevenson 'A' - #8	Panhandle Hutchinson County Fld.
Proved Producing	Stevenson 'A' - #9	Panhandle Hutchinson County Fld.
Proved Producing	Stevenson 'A' - #10	Panhandle Hutchinson County Fld.
Proved Producing	Stevenson 'A' - #13	Panhandle Hutchinson County Fld.
Proved Producing	Stevenson 'A' - #16	Panhandle Hutchinson County Fld.
Proved Producing	Stevenson 'A' - #17	Panhandle Hutchinson County Fld.
Proved Producing	Stevenson 'A' - #18	Panhandle Hutchinson County Fld.
Proved Producing	Stevenson 'A' - #20	Panhandle Hutchinson County Fld.
Proved Producing	Stevenson 'A' - #27	Panhandle Hutchinson County Fld.
Proved Producing	Faith #1	Panhandle Gray County Field
Proved Producing	Faith #2	Pan Handle Gray County Field
Proved Producing	Magic - #3	Panhandle Carson County Field
Proved Producing	Magic - #4	Panhandle Carson County Field
Proved Producing	Enserch - #1	Panhandle Carson County Field
Proved Producing	Cobb - #1	Panhandle Gray County Field
Proved Producing	Cobb - #4	Panhandle Gray County Field
Proved Producing	Bell #2	Panhandle Gray County Field
Proved Producing	Bell #3	Panhandle Gray County Field
Proved Producing	Bell #4	Panhandle Gray County Field
Proved Producing	Bell #5	Panhandle Gray County Field
Proved Producing	Meers L & W - #1	Panhandle Gray County Field
Proved Producing	Walberg - #1	Panhandle Gray County Field
Proved Producing	Short - #1	Panhandle Gray County Field
Proved Producing	Short - #7	Panhandle Gray County Field
Proved Producing	Saunders - #B-7-7	Panhandle Gray County Field
Proved Producing	Heaston - #1	Panhandle Gray County Field
Proved Producing	Heaston - #2	Panhandle Gray County Field
Proved Producing	Heaston - #3	Panhandle Gray County Field
Proved Producing	Heaston - #4	Panhandle Gray County Field
Proved Producing	Heaston - #5	Panhandle Gray County Field
Proved Producing	Heaston - #6	Panhandle Gray County Field
Proved Producing	Heaston - #8	Panhandle Gray County Field

Proved Producing	Heaston - #10	Panhandle Gray County Field
Proved Producing	Heaston - #12	Panhandle Gray County Field
Proved Producing	J J Wall - #2	Panhandle Gray County Field
Proved Producing	J J Wall - #3	Panhandle Gray County Field
Proved Producing	J J Wall - #6	Panhandle Gray County Field
Proved Producing	J J Wall - #7	Panhandle Gray County Field
Proved Producing	J J Wall - #8	Panhandle Gray County Field
Proved Producing	J J Wall - #10	Panhandle Gray County Field
Proved Producing	J J Wall - #11	Panhandle Gray County Field
Proved Producing	J J Wall - #12	Panhandle Gray County Field
Proved Producing	J J Wall - #14	Panhandle Gray County Field
Proved Producing	Kinzer - #3	Panhandle Gray County Field
Proved Producing	Kinzer - #4	Panhandle Gray County Field
Proved Producing	Leopold 'B' - #2	Panhandle Gray County Field
Proved Producing	Montague County - Daube #1	Eanes Field
Proved Producing	Montague County - Donald & Donald #4	Eanes Field
Proved Producing	Montague County - Donald & Donald #5	Eanes Field
Proved Producing	Montague County - Donald & Donald #6	Eanes Field
Proved Producing	Montague County - Kramer #1	Eanes Field
Proved Producing	Shelby County - Savell A #1H	Se Martinsville (James Lime) Field
Proved Producing	Shelby County - Savell #2H	Se Martinsville (James Lime) Field
Proved Producing	Shelby County - Savell C #3H	Se Martinsville (James Lime) Field
Proved Producing	Stephens County - Pugh #6 (JV1)	Moon, Se (Marble Falls)
Proved Producing	Stephens County - Pugh #7 (JV2)	Moon, Se (Marble Falls)
Proved Producing	Stephens County - Pugh #8 (JV3)	Moon, Se (Marble Falls)
Proved Producing	Stephens County - Pugh #9 (JV4)	Moon, Se (Marble Falls)
Proved Producing	Stephens County - Pugh #10 (JV5)	Moon, Se (Marble Falls)
Proved Producing	Stephens County - Pugh #11 (JV6)	Moon, Se (Marble Falls)
Proved Producing	Stephens County - Pugh #12 (JV7)	Moon, Se (Marble Falls)
Proved Producing	Mostyn 2H	Karns County Field
Proved Producing	Fortenberry 2H	Wise County Field
Proved Producing	Texas Two Step (Vision)	Gonzalez County Field
Proved Non-Producing	Bill Phillips - #1	Panhandle Hutchinson County Fld.
Proved Non-Producing	Bill Phillips - #2	Panhandle Hutchinson County Fld.
Proved Non-Producing	Bill Phillips - #3	Panhandle Hutchinson County Fld.
Proved Non-Producing	Bill Phillips - #4	Panhandle Hutchinson County Fld.
Proved Non-Producing	Bill Phillips - #5	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #4	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #5	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #9	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #10	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #11	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #12	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #13	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #14	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #15	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #16	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #20	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #21	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #22	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #25	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #26	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #27	Panhandle Hutchinson County Fld.
Proved Non-Producing	Stevenson 'A' - #28	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'C' #1	Panhandle Hutchinson County Fld.

Proved Non-Producing	Mayfield 'C' #2	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'C' #3	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'C' #4	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'C' #5	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'C' #6	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'C' #13	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'C' #15	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'C' #16	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'C' #18	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #1	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #2	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #3	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #4	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #5	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #6	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #7	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #8	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #9	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #10	Panhandle Hutchinson County Fld.
Proved Non-Producing	Mayfield 'B' #11	Panhandle Hutchinson County Fld.
Proved Non-Producing	WAB - #1	Panhandle Carson County Field
Proved Non-Producing	WAB - #3	Panhandle Carson County Field
Proved Non-Producing	WAB - #4	Panhandle Carson County Field
Proved Non-Producing	Boney - #10	Panhandle Carson County Field
Proved Non-Producing	Boney - #12	Panhandle Carson County Field
Proved Non-Producing	Boney - #13	Panhandle Carson County Field
Proved Non-Producing	Boney - #16	Panhandle Carson County Field
Proved Non-Producing	Boney - #19	Panhandle Carson County Field
Proved Non-Producing	Boney - #20	Panhandle Carson County Field
Proved Non-Producing	Boney - #21	Panhandle Carson County Field
Proved Non-Producing	Boney - #22	Panhandle Carson County Field
Proved Non-Producing	Boney - #23	Panhandle Carson County Field
Proved Non-Producing	Boney - #24	Panhandle Carson County Field
Proved Non-Producing	Boney - #25	Panhandle Carson County Field
Proved Non-Producing	Cobb - #5	Panhandle Gray County Field
Proved Non-Producing	Walberg - #8	Panhandle Gray County Field
Proved Non-Producing	Walberg - #9	Panhandle Gray County Field
Proved Non-Producing	Walberg - #11	Panhandle Gray County Field
Proved Non-Producing	Short - #4	Panhandle Gray County Field
Proved Non-Producing	Short - #6	Panhandle Gray County Field
Proved Non-Producing	Short 'B' #2	Panhandle Gray County Field
Proved Non-Producing	Short 'A' #1	Panhandle Gray County Field
Proved Non-Producing	Short 'A' #4	Panhandle Gray County Field
Proved Non-Producing	Heaston - #7	Panhandle Gray County Field
Proved Non-Producing	Heaston - #8	Panhandle Gray County Field
Proved Non-Producing	Heaston - #9	Panhandle Gray County Field
Proved Non-Producing	J J Wall - #1	Panhandle Gray County Field
Proved Non-Producing	J J Wall - #4	Panhandle Gray County Field
Proved Non-Producing	J J Wall - #6	Panhandle Gray County Field
Proved Non-Producing	J J Wall - #9	Panhandle Gray County Field
Proved Non-Producing	Leopold 'B' - #1	Panhandle Gray County Field
Proved Non-Producing	Leopold 'B' - #3	Panhandle Gray County Field
Proved Non-Producing	Leopold 'B' - #4	Panhandle Gray County Field
Proved Non-Producing	Leopold 'B' - #5	Panhandle Gray County Field
Proved Non-Producing	Leopold 'B' - #6	Panhandle Gray County Field
Proved Non-Producing	Leopold 'B' - #7	Panhandle Gray County Field
Proved Non-Producing	Leopold 'B' - #8	Panhandle Gray County Field
Proved Non-Producing	Heithold - #102	Panhandle Gray County Field
Proved Non-Producing	Heithold - #103	Panhandle Gray County Field

Proved Non-Producing	Heithold - #106	Panhandle Gray County Field
Proved Non-Producing	Heithold - #107	Panhandle Gray County Field
Proved Non-Producing	Brown - #204	Panhandle Gray County Field
Proved Non-Producing	Brown - #205	Panhandle Gray County Field
Proved Non-Producing	Brown - #207	Panhandle Gray County Field
Proved Non-Producing	Brown - #208	Panhandle Gray County Field
Proved Non-Producing	Brown - #210	Panhandle Gray County Field
Proved Non-Producing	Brown - #212	Panhandle Gray County Field
Proved Non-Producing	Brown - #213	Panhandle Gray County Field
Proved Non-Producing	Brown - #214	Panhandle Gray County Field
Proved Non-Producing	Brown - #216	Panhandle Gray County Field
Proved Non-Producing	Brown - #217	Panhandle Gray County Field
Proved Non-Producing	Brown - #218	Panhandle Gray County Field
Proved Non-Producing	Jackson - #306	Panhandle Gray County Field
Proved Non-Producing	Crow - #401	Panhandle Gray County Field
Proved Non-Producing	Crow - #404	Panhandle Gray County Field
Proved Non-Producing	Crow - #407	Panhandle Gray County Field
Proved Non-Producing	Crow - #410	Panhandle Gray County Field
Proved Non-Producing	Brown 'A' #501	Panhandle Gray County Field
Proved Non-Producing	Brown 'A' #502	Panhandle Gray County Field
Proved Non-Producing	Brown 'A' #504	Panhandle Gray County Field
Proved Non-Producing	Brown 'A' #505	Panhandle Gray County Field
Proved Non-Producing	Brown 'A' #506	Panhandle Gray County Field
Proved Non-Producing	Brown 'A' #507	Panhandle Gray County Field
Proved Non-Producing	Leopold 'A' #1	Panhandle Gray County Field
Proved Non-Producing	Leopold 'A' #2	Panhandle Gray County Field
Proved Non-Producing	Leopold 'A' #4	Panhandle Gray County Field
Proved Non-Producing	Leopold 'A' #6	Panhandle Gray County Field
Proved Non-Producing	Leopold 'A' #7	Panhandle Gray County Field
Proved Non-Producing	Leopold 'A' #8	Panhandle Gray County Field
Proved Non-Producing	Leopold 'C' #1	Panhandle Gray County Field
Proved Non-Producing	Leopold 'C' #2	Panhandle Gray County Field
Proved Non-Producing	Leopold 'C' #3	Panhandle Gray County Field
Proved Non-Producing	Leopold 'C' #4	Panhandle Gray County Field
Proved Non-Producing	Leopold 'C' #5	Panhandle Gray County Field
Proved Non-Producing	Skoog #1	Panhandle Gray County Field
Proved Non-Producing	Skoog #2	Panhandle Gray County Field
Proved Non-Producing	Skoog #3	Panhandle Gray County Field
Proved Non-Producing	Skoog #4	Panhandle Gray County Field
Proved Non-Producing	Skoog 'A' #1	Panhandle Gray County Field
Proved Non-Producing	Skoog 'A' #1	Panhandle Gray County Field
Proved Non-Producing	Skoog 'A' #1	Panhandle Gray County Field
Proved Non-Producing	Skoog 'A' #1	Panhandle Gray County Field
Proved Non-Producing	Montague County - Daube #2	Eanes Field
Proved Non-Producing	Shelby County - Gene Borders #2H	Angie, James Lime
Salt Water Disposal Well	Stevenson 'A' - #14	Panhandle Hutchinson County Fld.
Salt Water Disposal Well	Magic - #2	Panhandle Carson County Field
Salt Water Disposal Well	Cobb - #2	Panhandle Gray County Field
Salt Water Disposal Well	Walberg - #9	Panhandle Gray County Field
Salt Water Disposal Well	Short #2	Panhandle Gray County Field
Salt Water Disposal Well	J J Wall - #5W	Panhandle Gray County Field
Salt Water Disposal Well	Kinzer - #2W	Panhandle Gray County Field
Salt Water Disposal Well	Brown - #211G	Panhandle Gray County Field
Salt Water Disposal Well	Crow - #406	Panhandle Gray County Field
Undeveloped Acreage	St. Chareles, Parrish, LA - 170 Acres	Herbert Sand
Undeveloped Acreage	Shelby County - Savell Area - 752 acres	Angie, James Lime Depth
Undeveloped Acreage	Shelby County - Gene Borders Area - 500 acres	Haynesville Depth

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:

Year Ended December 31,
	2013		2012
Net Production:
Oil (Bbl)		26,106		26,413
Natural Gas (Mcf)		152,470		134,736
Barrel of Oil Equivalent (Boe)		51,517		48,869
Productive Wells		66		58

Oil and Natural Gas Sales:
Oil (in thousands)	$	2,449	$	2,400
Natural Gas (in thousands)	$	1,279	$	1,282
Total (thousands)	$	3,728	$	3,682

Average Sales Price:
Oil ($ per Bbl)	$	93.80	$	90.86
Natural Gas ($ per Mcf)	$	8.39	$	9.51
Barrel of Oil Equivalent ($ per Boe)	$	72.36	$	75.34

Oil and Natural Gas Costs:
Lease Operating Expenses (in thousands)	$	948	$	1,114
Production taxes (in thousands)	$	199	$	177
Other operating expenses (in thousands)		-		-
Average production cost per Boe	$	22.26	$	26.42

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:

(in thousands)	Year Ended December 31,
	2013		2012
Unproved prospects	$	0	$	0
Proved prospects	$	860	$	1,477
Development and exploration costs	$	716	$	1,011
Total asset retirement cost incurred	$	37		1
Total consolidated operations	$	1,613	$	2,489

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 prospectus.

Years Ended December 31, 2013

Estimated Proved Natural Gas and Oil Reserves:
Net natural gas reserves (MMcf):
Proved developed		6,609
Proved undeveloped		3,894
Total		10,503
Net oil reserves (MBbls):
Proved developed		3,313
Proved undeveloped		3,303
Total		6,616
Estimated Present Value of Net Proved Reserves:
PV-10 value (in thousands)
Proved developed	$	106,316
Proved undeveloped		121,704
Total	$	229,370

Prices Used in Calculating Reserves:
Natural gas (per Mcf)	$	3.67
After adjustments for liquids and BTU content	$	9.52
Oil (per Bbl)	$	96.94
After adjustments for liquids and BTU content	$	95.75

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

	Crude Oil (Bbl)			Natural Gas (Mcf)
PROVED-DEVELOPED AND UNDEVELOPED RESERVES
December 31, 2011		6,720,020			10,674,620

Revisions of previous estimates		(325,517	)		(454,154	)
Extensions and discoveries
Acquisitions of reserves		20,730			150,320
Production		(26,413	)		(134,736	)

December 31, 2012		6,388,820			10,236,050

Revisions of previous estimates		245,536			(372,343	)
Extensions and discoveries
Acquisitions of reserves		7,760			47,007
Production		(26,106	)		(152,470	)

December 31, 2013		6,616,010			10,502,930

PROVED DEVELOPED RESERVES
December 31, 2013		3,313,400			6,609,080
December 31, 2012		3,357,200			6,323,250

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.

The Quarter Ended*	HIGH		LOW

March 31, 2012		4.00		4.00
June 30, 2012		4.00		2.00
September 30, 2012	$	2.00	$	2.00
December 31, 2012	$	2.00	$	2.00

The Quarter Ended*	HIGH		LOW


March 31, 2013		6.00		2.00
June 30, 2013		4.00		2.00
September 30, 2013		6.00		1.45
December 31, 2013	$	1.50	$	1.11

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

From October 2013 through March 2014, a total of 1,247,250 shares of Series G preferred stock were sold for a sum of $1,247,250.

The Series G preferred stock carries an 8% annual dividend and may be converted any time after the first year at the request of the shareholder or the Company into two (2) shares of common stock of the Company and two (2) warrants that will allow the holder, for a period of two years from the date of issue, to acquire one additional share of the Company’s common stock for each warrant at a purchase price of $3.75 per share. The Series G preferred stock issued in 2014 resulted in a beneficial conversion feature at the date of issuance.

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 prospectus. The following Management’s 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 prospectus 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 prospectus. Although we believe that the assumptions underlying the forward-looking statements contained in this prospectus 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.

	Net Production		Price		Revenue
										Net Cash
	Oil	Gas	Oil ($)	Gas ($)	Oil ($)	Gas ($)	Total ($)	Taxes ($)	LOE ($)	($)
For the year ended December 31, 2012	26,413	134,736	90.86	9.51	2,400,000	1,282,000	3,682,000	177,000	1,114,000	2,391,000
For the year ended December 31, 2013	26,106	152,470	93.81	8.39	2,449,000	1,279,000	3,728,000	199,000	1,147,000	2,382,000
Variance	(307)	17,734	2.95	(1.12)	49,000	(3,000)	46,000	22,000	(33,000)	9,000

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.

LIQUIDITY AND CAPITAL RESOURCES

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.

Net cash used in investing activities of $871,000 was utilized to develop our oil and gas assets during the year 2013 and acquire additional proved producing properties in our core areas. This is a decrease of $1,254,000 from the same period in 2012.

Net cash provided by (used in) financing activities increased by $2,937,000 as the Company generated a considerable amount of cash through equity sales of the Company’s preferred stock as well as additional borrowings through the line of credit with GreenBank.

As of December 31, 2013, the Company currently has no material agreements for capital expenditures.

As of December 31, 2013, the current terms of the Company’s credit facility with Green Bank are $17,500,000, that matures on June 1, 2015 with a 4-4.5% annual floating interest rate which requires an approximate monthly payment of $63,000.

Since inception we have funded our operations primarily through equity and debt financings and we expect that we will continue to fund our operations through the equity and debt financing. We currently intend to raise our needed additional working capital primarily through private placement offerings of our common and preferred stock. However we may also consider doing a public offering as an alternative. There can be no assurance that any private or public offering we may undertake will be successful or raise sufficient capital to fund our business plan. If we raise additional financing by issuing common stock, our existing stockholders’ ownership will be diluted. Obtaining commercial loans, assuming those loans would be available, will increase our liabilities and future cash commitments.

There is no assurance that we will be able to maintain operations at a level sufficient for investors to obtain a return on their investment in our common stock.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2013, the off-balance sheet arrangements and transactions that we had entered into included operating lease agreements, personal guarantees of our line of credit with Greenbank by three of the officers and majority stockholders and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources currently or in the future.

Application of Critical Accounting Policies

Our financial statements and accompanying notes are prepared in accordance with generally accepted accounting principles in the United States. Preparing financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses. These estimates and assumptions are affected by management’s application of accounting policies. We believe that understanding the basis and nature of the estimates and assumptions involved with the following aspects of our financial statements is critical to an understanding of our financials.

We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, politics, global economics, general business conditions and other factors. Our significant estimates are related to the valuation of warrants and options.

There are accounting policies that we believe are significant to the presentation of our financial statements. The most significant of these accounting policies relates to the accounting for our research and development expenses and stock-based compensation expense.

Stock-based Compensation

We account for all stock-based payments and awards under the fair value based method.

Stock-based payments to non-employees are measured at the fair value of the consideration received, or the fair value of the equity instruments issued, or liabilities incurred, whichever is more reliably measurable. The fair value of stock-based payments to non-employees is periodically re-measured until the counterparty performance is complete, and any change therein is recognized over the vesting period of the award and in the same manner as if we had paid cash instead of paying with or using equity based instruments. The cost of the stock-based payments to non-employees that are fully vested and non-forfeitable as at the grant date is measured and recognized at that date, unless there is a contractual term for services in which case such compensation would be amortized over the contractual term.

We account for the granting of share purchase options to employees using the fair value method whereby all awards to employees will be recorded at fair value on the date of the grant. The fair value of all share purchase options are expensed over their vesting period with a corresponding increase to additional capital surplus. Upon exercise of share purchase options, the consideration paid by the option holder, together with the amount previously recognized in additional capital surplus, is recorded as an increase to share capital.

We use the Black-Scholes option valuation model to calculate the fair value of share purchase options at the date of the grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in assumptions can materially affect the fair value estimate and therefore the Black-Scholes model does not necessarily provide a reliable single measure of the fair value of our share purchase options.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None. Previously disclosed on form 8-K and filed with the SEC on July 19, 2013.

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

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2013. Disclosure controls and procedures means controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (a) recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms and (b) accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Based on the evaluation of our disclosure controls and procedures as of December 31, 2013, our Chief Executive Officer and Chief Financial Officer concluded that, as of such date, our disclosure controls and procedures were ineffective, due to the material weaknesses in our internal control over financial reporting described below.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2013 based on the guidelines established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. (COSO).

Because of its inherent limitations, internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collision or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with established policies or procedures may deteriorate.

A material weakness is a control deficiency, or a combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. As a result of our management’s assessment of the effectiveness of internal control over financial reporting, we have identified the following material weaknesses that existed as of December 31, 2013:

1. Inadequate and ineffective controls over the financial statement close process.

In conjunction with the year-end financial close, our procedures and controls to ensure that accurate financial statements in accordance with generally accepted accounting principles could be prepared and reviewed on timely basis were not operating effectively. Such ineffective procedures and controls include (a) ineffective segregation of duties; (b) insufficient documentation of accounting policies and procedures and retention of historical accounting portions. As a result of the above deficiencies, material and less significant post-closing adjustments were identified by our independent registered public accounting firm, Rothstein Kass LLP, and recorded in our financial statements as of and for the year ended December 31, 2013

2. Inadequate staffing within the accounting organization.

During 2013, there were numerous changes in our accounting personnel, both on staff and third party support. This has led to our not having a sufficient number of experienced personnel in the accounting organization to provide reasonable assurance that transactions are being recorded as necessary to ensure timely preparation of financial statements in accordance with generally accepted accounting principles, including the preparation of our Annual Report on Form 10-K. We consider this weakness to be a material weakness in the operation of entity-level controls and operation level controls. The ineffectiveness of such controls can result in misstatement to assets, liabilities, revenues, and expenses.

Our management concluded that, due to the material weaknesses described above, we did not maintain effective internal control over financial reporting as of December 31, 2013.

3. Remedial actions

In an effort to remediate the identified deficiencies, we have commenced, and are continuing to implement, a number of changes to our internal control over financial reporting. These following changes will be made before the end of 2014:

•

Proper accounting procedures will be put in place

•

Monthly reconciliation of the financials

Additionally, in response to the identified deficiencies, we intend to implement additional remedial measures, including but not limited to the following:

	•	Hiring additional accounting personnel; and
	•	Improving our documentation and training related to policies and procedures for the controls related to our significant accounts and processes.

Changes in Internal Control over Financial Reporting

Except as described above, during its assessment of our internal control over financial reporting our management identified no change in our internal control over financial reporting that occurred during the fourth quarter of 2013 that has materially affected, or is reasonably likely to affect, our internal control over financial reporting.

ITEM 9B – OTHER INFORMATION

None

PART III

ITEM 10:

Directors and Executive Officers

NAME	AGE	POSITION	Director/Officer Since
Don Crosbie	69	President, ANC Holdings, LLC and Chairman of the Board of Directors.	2002
Stuart G. Hagler	49	Chief Executive Officer, Director	2013
W.A. Westmorland	51	President-Operations, Director	2013
David May	49	President-Acquisitions, Director	2013
Derrick May	24	Corporate Secretary	2013

Don Crosbie was the former President, Chief Executive Officer of ANC Holdings, LLC that was sold in June of 2013 by the Company. He is our former President and current Chairman of the Board positions he has held since October 2002. From July 2001 until October 2002, Mr. Crosbie was President and CEO of Xactimed, a claims processing and clearing house company serving the hospital market. From September 2000 to July 2001, Mr. Crosbie served as CFO and President of North American Operations of Blue Wave Systems, a high density DSP board supplier to the telecom infrastructure market, including media gateways and 2 ½ and 3 G wireless.

Stuart G. Hagler , is a director and Chief Executive Officer for TransCoastal and has been with TransCoastal since its inception in 1998. He is also a Manager and Member of TransCoastal Partners, LLC, a company that manages oil and gas joint venture partnerships. In 1987 he received his Bachelor's degree in Economics from Southern Methodist University in Dallas, Texas and in 2009 he received his Master's Degree in Business Administration from the same school. His primary responsibility as CEO is overseeing the day-to-day activities and managing the strategic direction of TransCoastal.

W. A. Westmoreland , is a director and President-Operations for TransCoastal and has been with TransCoastal since its inception in 1998 and serves as a Manager and Member of TransCoastal Partners, LLC, a company that manages oil and gas joint venture partnerships. Mr. Westmoreland's primary responsibility is overseeing operation of the corporations existing wells and supervising the drilling of the corporation's new wells through TransCoastal's operating subsidiary CoreTerra Operating LLC.

David J. May , is a director and President-Acquisitions for TransCoastal and has been with TransCoastal since its inception in 1998. Mr. May is also a Manager and Member of TransCoastal Partners, LLC. His primary responsibilities are for lease acquisition working directly with prospect generation sources, and the due diligence associated with those properties.

Regulatory actions

On April 16, 2008, Stuart Hagler, David May, W.A. Westmoreland, TransCoastal Partners, LLC, and the Couba Du Large Joint Venture entered into a Stipulation with the California Securities Commissioner, without admitting or denying any of the opinions or findings in the Desist and Refrain Order, that alleged that joint venture interests were offered and sold in California by TransCoastal Partners and the named individuals "without being qualified in violation of California Corporations Code section 25110". The aforementioned parties settled with the State of California stipulating and agreeing to the finality of the Desist & Refrain Order, which prevents them from offering securities in California unless the securities are qualified under applicable California securities law as registered securities or exempt therefrom.

Derrick A. May Corporate Secretary. Derrick was appointed Corporate Secretary in May of 2013. Derrick originally joined TransCoastal in February of 2013 as their Financial Analyst. Derrick graduated from Oklahoma State University in Stillwater, Oklahoma in 2012. He was on the Dean’s List during his tenure there and was awarded a B.S. in Finance. Derrick previously served an internship at Highland Capital Management in Dallas. Mr. May is the son of David May, a director and our President - Acquisitions.

Compliance with Section 16(a) of the Securities Exchange Act of 1934

Section 16(a) of the Securities Exchange Act of 1934 requires our executive officers and directors and persons who own more than 10% of our common stock to file with the Securities and Exchange Commission initial statements of beneficial ownership, reports of changes in ownership and annual reports concerning their ownership of our common stock and other equity securities, on Forms 3, 4 and 5 respectively. Executive officers, directors and greater than 10% shareholders are required by the Securities and Exchange Commission regulations to furnish us with copies of all Section 16(a) reports that they file.

Based solely on our review of the copies of such forms received by us, or written representations from certain reporting persons, we believe that during fiscal year ended December 31, 2012, all filing requirements applicable to our officers, directors and greater than 10% percent beneficial owners have complied.

Code of Ethics

We have adopted a code of ethics (within the meaning of Item 406(b) of Regulation S-K) that applies to our Board, Chief Executive Officer, Chief Financial Officer and such other persons designated by our Board or an appropriate committee thereof. The code of ethics is designed to deter wrongdoing and to promote honest and ethical conduct and full, fair, accurate, timely and understandable disclosure in our SEC reports and other public communications. The code of ethics promotes compliance with applicable governmental laws, rules and regulations. We have posted our policy on our website at www.transcostal.net .

Composition of the Board

Our Board currently consists of four members, including our Chief Executive Officer. We are currently seeking additional directors that qualify as independent directors under the independence requirements of Rule 10A-3 of the Exchange Act.

Board Leadership Structure

Our Board understands that there is no single generally accepted approach to providing board leadership and that given the dynamic and competitive environment in which we operate, the right board leadership structure may vary as circumstances warrant. To this end, our Board has no policy mandating the combination or separation of the roles of Chairman and Chief Executive Officer and believes the matter should be discussed and considered from time to time as circumstances change. Currently, the roles of Chairman and Chief Executive Officer are filled by the separate individuals. This leadership structure is appropriate for us at this time as we are a smaller company and we believe this structure provides clarity of leadership.

Board Oversight of Risk Management

Our full Board oversees our risk management process. Our Board oversees a company-wide approach to risk management, carried out by management. Our full Board determines the appropriate risk for us generally, assesses the specific risks faced by our company and reviews the steps taken by management to manage those risks.

While the full Board maintains the ultimate oversight responsibility for the risk management process, its committees oversee risk in certain specified areas. In particular, our compensation committee is responsible for overseeing the management of risks relating to our executive compensation plans and arrangements and the incentives created by the compensation awards it administers. Our audit committee oversees management of enterprise risks as well as financial risks and potential conflicts of interests. Pursuant to the Board’s instruction, management regularly reports on applicable risks to the relevant committee or the full Board, as appropriate, with additional review or reporting on risks conducted as needed or as requested by the Board and its committees.

ITEM 11:

Officers

The Company has entered into employment agreements with its four 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.

In addition to their salary the officers receive certain benefits such as health insurance similar to the benefits received by the other employees of the Company. The Company may, at its sole discretion, obtain a “key man” life insurance policy on each of its officers with the Company being the beneficiary of such insurance. The following table represents the salary and stock grants received by our officers and non-employee director in fiscal years 2011 and 2012.

ITEM 12:

The following table summarizes certain information as of December 31, 2013 with respect to the beneficial ownership of our Common Stock by (1) our directors, (2) our Presidents and Chief Executive Officer, our Chief Financial Officer (our principal accounting officer) and our most highly-compensated executive officers as of December 31, 2013 (or any executive officer who would have been among the most highly-compensated but for the fact that such an individual was not serving as an executive officer as of December 31, 2013) whose total salary and bonus for the fiscal year ended December 31, 2012 exceeded $120,000 for services in all capacities to the Company (collectively, the " Named Executive Officers "), (3) stockholders known by us to own beneficially 5% or more of the shares of our Common Stock, and (4) all of our Named Executive Officers and directors as a group. As of December 31, 2013, the Company had 22,453,773 shares of Common Stock issued and outstanding.

Beneficial ownership is determined in accordance with the rules of SEC. Under SEC rules, a person is deemed to be a "beneficial owner" of a security if that person has or shares voting power or investment power, which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed to be a beneficial owner of the same securities and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest.

The following table is based upon information supplied by officers, directors and principal stockholders and Schedules 13D and 13G filed with the SEC and information supplied by our transfer agent, Securities Transfer Corporation, as of the most recent practicable date. Unless otherwise indicated in the footnotes to this table and subject to community property laws where applicable, we believe that each of the stockholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned. Applicable percentages are based on 22,453,773 shares outstanding on December 31, 2013 provided that any additional shares of common stock that a stockholder has the right to acquire within 60 days after December 31, 2013 pursuant to grants of stock options or awards of restricted stock are deemed to be outstanding and beneficially owned by the person holding such options or restricted stock for the purpose of computing the number of shares beneficially owned and the percentage ownership of such person, but are not deemed to be outstanding for the purpose of computing the percentage ownership of any other person.

STOCK BENEFICIALLY OWNED BY OR DIRECTORS AND EXECUTIVE OFFICERS

Name and address of beneficial owner	Class of Security	Amount and Beneficial Ownership		Percent of Class
Don Crosbie, Chairman of the Board of Directors	Common Stock		19,967		.1	%
17304 Preston Rd., Suite 700
Dallas TX 75252

Stuart Hagler, Chief Executive Officer	Common Stock		6,000,000		26.7	%
17304 Preston Rd., Suite 700
Dallas TX 75252

A.W. Westmoreland, President of Operations	Common Stock		5,847,686		26.0	%
17304 Preston Rd., Suite 700
Dallas TX 75252

Dave May, President of Acquisitions	Common Stock		5,718,603		25.5	%
17304 Preston Rd., Suite 700
Dallas TX 75252


All our directors and executive officers as a group			17,586,256		78.3	%

ITEM 13:

There have been no transactions, or proposed transactions, which have materially affected or will materially affect us in which any director, executive officer or beneficial holder of more than 5% of the outstanding common stock, or any of their respective relatives, spouses, associates or affiliates, has had or will have any direct or material indirect interest. We have no policy regarding entering into transactions with affiliated parties.

During the year ended December 31, 2012, the Company issued notes receivable, related party of approximately $1,477 to companies owned by members of the Company management or directly to members of Company management. On October 29, 2012, these notes receivable, related party, were settled through the assignment of certain working and revenue interests of wells located in Gray County, Texas to the Company. This acquisition of oil and natural gas properties is further described in Note 13 to the Consolidated Financial Statements.

During the year ended December 31, 2012, the Company was issued a note payable, related party of approximately $125 from a member of the Company management. During the year ended December 31, 2013, the related party forgave this note payable owed by the company as described in Note 13 to the Consolidated Financial Statements.

ITEM 14:

The company pays its auditors, Rothstein Kass, $80,500 per year as a retainer for their year end audit. There are also other costs associated with the filing of the company’s quarterly reports at approximately $13,500 per quarterly review.

Exhibit List:

EXHIBIT INDEX

Exhibit Number	Description
(3)	Articles of Incorporation and Bylaws
3.1* *	Certificate of Incorporation as amended (incorporated by reference to an exhibit to our Form 8K filed on July 3, 2013 File No. 001-14665, Ex. 10.1)
3.1(a)**	Certificate of Designation of Series F Preferred Stock (incorporated by reference to an exhibit to our Form 8K filed on May 15, 2013 File No. 001-14665, Ex. 3(i))
3.1(b)**	Certificate of Designation of Series G Preferred Stock (incorporated by reference to an exhibit to our Form S1 filed on October 4, 2013 File No. 001-14665, Ex. 3.1(b))
3.1(c)**	Certificate of Designation of Series H Preferred Stock (incorporated by reference to an exhibit to our Form S1/A filed on May 9, 2014 File No. 001-14665, Ex. 3.1(c))
3.2**	Bylaws as amended (incorporated by reference to an Annex B to our Definitive 14A filed on August 9, 2013 File No. 001-14665)
(4)	Instruments defining rights of security holders, including indentures
4.1**	Specimen Stock Certificate (incorporated by reference to an exhibit on Form 10Q filed on August 14, 2013 File No. 001-14665, Ex. 4.1(1))
(5)	Opinion re: legality
5.1**	Opinion of Kane Russell Coleman & Logan PC
(10)	Material Contracts
10.1**	Amended Acquisition Agreement by and between Claimsnet.com, Inc. and TransCoastal Corporation (incorporated by reference to an exhibit on Form 10Q filed on May 7, 2013 File No. 001-14665, Ex. 2.2))
10.2**	Stock Purchase Agreement for sale of ANC Holdings, Inc. (incorporated by reference to an exhibit on Form 8K filed on July 3, 2013 File No. 001-14665)
10.3* *	2013 Stock Incentive Program (incorporated by reference to Annex A on Form DEF 14A filed on August 9, 2013 File No. 001-14665)
10.4**	Employment Agreement with Stuart Hagler dated January 1, 2011 (incorporated by reference to an exhibit to Form 8K filed on June 13, 2013 File No. 001-14665, Ex. 10.1)
10.5**	Employment Agreement with David May dated January 1, 2011 (incorporated by reference to an exhibit to Form 8K filed on June 13, 2013 File No. 001-14665, Ex. 10.2)
10.6**	Employment Agreement with Wilbur A. Westmoreland dated January 1, 2011 (incorporated by reference to an exhibit to Form 8K filed on June 13, 2013 File No. 001-14665, Ex. 10.3)
10.7**	Employment Agreement with Judson Hoover dated January 1, 2013 (incorporated by reference to an exhibit to Form 8K filed on June 13, 2013 File No. 001-14665, Ex. 10.4)
10.8**	Amended Loan Agreement with Green Bank, N.A. (incorporated by reference to an exhibit to our Form S1 filed on October 4, 2013 File No. 001-14665, Ex. 10.8)
10.9**	First Amendment to Loan Agreement with Green Bank, N.A. (incorporated by reference to an exhibit to our Form S1 filed on October 4, 2013 File No. 001-14665, Ex. 10.9)
10.10**	Second Amendment to Loan Agreement with Green Bank, N.A. (incorporated by reference to an exhibit to our Form S1 filed on October 4, 2013 File No. 001-14665, Ex. 10.10)
10.11**	Davis Marketing Agreement (incorporated by reference to an exhibit to our Form S1/A filed on November 25, 2013 File No. 001-14665, Ex. 10.11)
10.12**	Eagle Rock Gas Marketing Agreement (incorporated by reference to an exhibit to our Form S1/A filed on November 25, 2013 File No. 001-14665, Ex. 10.12)
10.13**	Targa Gas Marketing Agreement (incorporated by reference to an exhibit to our Form S1/A filed on November 25, 2013 File No. 001-14665, Ex. 10.13)
10.14**	Valero Crude Oil Marketing Agreement (incorporated by reference to an exhibit to our Form S1/A filed on February 26, 2014 File No. 001-14665, Ex. 10.14)
10.15* *	PhillipsConoco Crude Oil Marketing Agreement (incorporated by reference to an exhibit to our Form S1/A filed on January 17, 2014 File No. 001-14665, Ex. 10.15)
10.16*	Seventh Amendment to Loan Agreement with Green Bank, N.A.
(14)	Code of Ethics
14.1* *	Code of Ethics (incorporated by reference to an exhibit to our Current Report on Form 10K filed on February 26, 2013 File No. 001-14665, Ex. 14)
(21)	Subsidiaries
21.1* *	CoreTerra Operating, LLC, a Texas limited liability company
(23)	Consents of experts and counsel
23.1**	Consent of Rothstein Kass
23.1(a)*	Updated Consent of Rothstein Kass
23.2**	Consent of Kane Russell Coleman & Logan PC (included in Exhibit 5.1)
(99)	Additional Exhibits
99.1**	Appraisal Report Summary (Reserve Report) dated January 1, 2013 (incorporated by reference to an exhibit to our Form S-1 filed October 4, 2014 File No. 001-14665, Ex. 99.1)
99.2**	Revised Appraisal Report (Reserve Report) dated January 1, 2013 (incorporated by reference to an exhibit to our Form S1/A filed May 9, 2014 File No. 001-14665, Ex. 99.2)
99.3**	Revised Appraisal Report (Reserve Report) dated January 1, 2014 (Incorporated by reference to an exhibit to our Form 10K filed May 9, 2014 File No. 001-14665, Ex. 99.3)

101

101.1NS XBRL Instance Document

101.SCH XBRL Taxonomy Schema

101.CAL XBRL Taxonomy Calculation Linkbase

101.LAB XBRL Taxonomy Label Linkbase

101.PRE XBRL Taxonomy Presentation Linkbase

101.DEF XBRL Taxonomy Definition Linkbase

* Filed herewith.

** Filed prior.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	TransCoastal Corporation

Date: June 16, 2014	By:	/s/ Stuart G. Hagler
	Chief Executive Officer and President (Principal Executive and Principal Financial and Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signatures	Title	Date

/s/ Donald Crosbie	Chairman of the Board of Directors	June 16, 2014
Donald Crosbie

/s/ Stuart G. Hagler	Director, Chief Executive Officer (Principal Executive and Accounting Officer)	June 16, 2014
Stuart G. Hagler

/s/ W.A. Westmoreland	Director, President of Operations	June 16, 2014
W.A. Westmoreland

/s/ David J. May	Director, President of Acquisitions	June 16, 2014
David J. May

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

INDEX TO FINANCIAL STATEMENTS


	Page
Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2013 (RESTATED) and 2012 (RESTATED)		F-3

Consolidated Statements of Operations for the Years Ended December 31, 2013 (RESTATED) and 2012 (RESTATED)		F-4

Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2013 (RESTATED) and 2012 (RESTATED)		F-5

Consolidated Statements of Cash Flows for the Years Ended December 31, 2013 (RESTATED) and 2012 (RESTATED)		F-6

Notes to Consolidated Financial Statements		F-8

F-1

F-2

TRANSCOASTAL CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

December 31,	2013			2012
	(RESTATED)			(RESTATED)
ASSETS

Current assets
Cash and cash equivalents	$	432		$	133
Accounts receivable		436			584
Current derivative assets					28
Other current assets		20			20
Total current assets		888			765
Oil and natural gas properties and other property and equipment
Oil and natural gas properties, full cost method, net of accumulated depletion		23,600			22,506
Other property and equipment, net of accumulated depreciation		470			567
Total oil and natural gas properties and other equipment, net		24,070			23,073
Other assets
Goodwill		485			485
Other non-current assets		387			105
Total other assets		872			590
Total assets	$	25,830		$	24,428

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities
Accounts payable and accrued liabilities	$	1,620		$	536
Notes payable, related party					125
Current asset retirement obligations		107			12
Current derivative liabilities		125
Current maturities of notes payable		17,512			150
Total current liabilities		19,364			823
Long-term liabilities
Notes payable		56			15,250
Stock to be issued		2,496			2,091
Asset retirement obligations		852			865
Derivative liabilities		18			6
Total long-term liabilities		3,422			18,212
Commitments and contingencies

Shareholders' equity
Preferred stock, $.001 par value; 25,000,000 shares authorized:
Series A, 0 and 37,500, respectively, preferred shares issued and outstanding
Series F, 0 and 3,721,036, respectively, preferred shares issued and outstanding					4		^[1]
Series G, 687,500 and 0, respectively, preferred shares issued and outstanding		1
Common stock, $.001 par value; 250,000,000 shares authorized; 22,453,773 and 0, respectively, shares issued and outstanding		23
Additional paid-in-capital		45,592			43,908		^[1]
Accumulated deficit		(42,572	)		(38,519	)
Total shareholders' equity		3,044			5,393
Total liabilities and shareholders' equity	$	25,830		$	24,428

[1] - Balance is reflective of Claimsnet.com Inc.'s acquisition of TransCoastal Corporation on March 18, 2013 (as amended April 24, 2013) as discussed in Note 1.

See accompanying notes to consolidated financial statements.

F-3

TRANSCOASTAL CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

Year ended December 31,	2013			2012
	(RESTATED)			(RESTATED)

Revenues
Oil, natural gas, and related product sales	$	3,728		$	3,682
Derivative losses		(269	)		(218	)
Drilling revenue, net					2,746
Other revenue		163			298
Total revenues		3,622			6,508

Expenses
Loss on turn-key contracts		1,468
Lease operating		1,147			1,291
Depreciation, depletion and amortization		704			660
Accretion of discount on asset retirement obligations		45			38
General and administrative		3,661			2,728
Total expenses		7,025			4,717
Operating income (loss)		(3,403	)		1,791

Other income (expense)
Interest income					2
Interest expense		(709	)		(713	)
Other income (expense)		59			(44	)
Total other expense, net		(650	)		(755	)
Net income (loss)	$	(4,053	)	$	1,036

Basic earnings per share:
Net income (loss) per basic common share	$	(0.18	)	$	0.05
Weighted average basic common shares outstanding		22,527,107			22,091,003		^[1]

Diluted earnings per share:
Net income (loss) per diluted common share	$	(0.18	)	$	0.05
Weighted average diluted common shares outstanding		22,527,107			22,166,003		^[1]

[1] - Balance includes equivalent Series F preferred stock, which contains the equivalent rights of common stock and was converted to common stock during the year ended December 31, 2013.

See accompanying notes to consolidated financial statements.

F-4

TRANSCOASTAL CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

	Common Stock				Series A Preferred Stock					Series F Preferred Stock						Series G Preferred Stock
	Shares		Amount		Shares			Amount		Shares			Amount			Shares		Amount		Additional Paid-in Capital			Accumulated Deficit			Total
																							(RESTATED)
Balances, December 31, 2011 ^[1]		-	$	-		-		$	-		3,640,123		$	4			-	$		$	42,308		$	(39,555	)	$	2,757

Issuance of Series A preferred stock						37,500															75						75
Forfeiture of Series F preferred stock																					1,350						1,350
Stock based compensation											80,913										175						175
Stock issued for services																											-
Net income																								1,036			1,036

Balances, December 31, 2012 ^[1]		-	$	-		37,500		$	-		3,721,036		$	4			-	$	-	$	43,908		$	(38,519	)	$	5,393


Recapitalization with Claimsnet.com, Inc.		178,250																			(1,602	)					(1,602	)
Spin-off of ANC Holdings, Inc.																					1,602						1,602
Issuance of Series A preferred stock						206,250															679						679
Constructive dividends on Series A preferred stock																					(266	)					(266	)
Issuance of Series G preferred stock																	687,250		1		2,440						2,441
Constructive dividends on Series G preferred stock																					(1,756	)					(1,756	)
Conversion of Series F preferred stock and
Series F preferred stock to be issued		21,323,978		21							(3,721,036	)		(4	)						(17	)					-
Conversion of Series A preferred stock		487,500		1		(243,750	)														(1	)					-
Issuance of common stock for deferred offering costs		256,578																			250						250
Forgiveness of notes payable, related party																					125						125
Stock based compensation		207,467		1																	269						270
Series A preferred dividend payments																					(39	)					(39	)
Net loss																								(4,053	)		(4,053	)

Balances, December 31, 2013		22,453,773	$	23		-		$	-		-		$	-			687,250	$	1	$	45,592		$	(42,572	)	$	3,044

[1] - Balance is reflective of Claimsnet.com Inc.'s acquisition of TransCoastal Corporation on March 18, 2013 (as amended April 24, 2013) as discussed in Note 1.

See accompanying notes to consolidated financial statements.

F-5

TRANSCOASTAL CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(AMOUNTS SHOWN IN THOUSANDS)

Year ended December 31,	2013			2012
	(RESTATED)			(RESTATED)
Cash flows from operating activities
Net income (loss)	$	(4,053	)	$	1,036
Adjustments to reconcile net income (loss) to net cash and cash equivalents provided by (used in) operating activities:
Depreciation, depletion and amortization		704			660
Stock based compensation		270			213
Stock to be issued for services					2
Accretion of discount on asset retirement obligations		45			38
Loss on turn-key contracts		1,468
Realized loss on derivative assets and liabilities					336
Unrealized (gain) loss on derivative assets and liabilities		165			(103	)
Increase (decrease) in cash and cash equivalents attributable to changes in operating assets and liabilities
Accounts receivable		(740	)		(311	)
Other current assets					6
Other non-current assets		(17	)		(5	)
Accounts payable and accrued liabilities		504			(301	)
Net cash and cash equivalents provided by (used in) operating activities		(1,654	)		1,571

Cash flows from investing activities
Development of oil and natural gas properties		(716	)		(1,011	)
Acquisition of oil and natural gas properties		(140	)
Disposition of oil and natural gas properties					391
Acquisition of other property and equipment		(15	)		(28	)
Issuance of notes receivable, related parties					(1,477	)
Net cash and cash equivalents used in investing activities		(871	)		(2,125	)

Cash flows from financing activities
Borrowings under notes payable		1,778			927
Repayments of notes payable		(6	)		(1,225	)
Payment of debt issuance costs					(15	)
Borrowings under notes payable, related party					125
Proceeds from issuance of Series A preferred stock, net of constructive dividend		413			75
Proceeds from issuance of Series G preferred stock, net of constructive dividend		685
Proceeds from stock to be issued		8
Payment of deferred offering costs		(15	)
Dividends paid on Series A preferred stock		(39	)
Net cash and cash equivalents provided by (used in) financing activities		2,824			(113	)
Net increase (decrease) in cash and cash equivalents		299			(667	)
Cash and cash equivalents , beginning of year		133			800
Cash and cash equivalents , end of year	$	432		$	133

See accompanying notes to consolidated financial statements.

F-6

TRANSCOASTAL CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

Year ended December 31,	2013		2012
	(RESTATED)		(RESTATED)
Supplemental disclosure of cash flow information
Cash paid during the year for interest	$	740	$	821

Supplemental disclosure of non-cash investing transactions
Acquisition of oil and natural gas properties through notes payable	$	322	$
Acquisition of oil and natural gas properties through settlement of notes receivable, related parties	$		$	1,477
Acquisition of oil and natural gas properties through stock to be issued	$	397	$
Acquisition of other property and equipment through notes payable	$	74	$
Capitalized asset retirement costs	$	37	$	1
Common stock issued for deferred offering costs	$	250	$
Net assets acquired and liabilities assumed through TransCoastal acquisition	$	1,602	$
Settlement of notes payable through sale of non-oil and gas assets and liabilities	$	1,602	$
Forgiveness of notes payable, related party	$	125	$
Conversion of Series F preferred stock	$	21	$
Conversion of Series A preferred stock	$	1	$

See accompanying notes to consolidated financial statements.

F-7

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

1.	Restatement of previously issued consolidated financial statements

The Company has restated certain amounts reported as of December 31, 2013 and 2012, and for each of the years in the two year period ended December 31, 2013. The restatement reflects adjustments of depletion expense and accumulated depletion based on the changes in reserve estimates for each of the years in the two year period ended December 31, 2013, which were included in the Company’s Annul Report on Form 10K.

The adjustments are noncash adjustments and have no impact on the Company’s cash flows. On May 6, 2014, the Company completed its assessment of the impact of the adjustments to the depletion expense and accumulated depletion for each of the years in the two year period ended December 31, 2013 and believes the effects of the restatements are as summarized in the following tables:

Prior to June 2014, the Company received communication from the majority participant of its lending group that the financial covenant failures at December 31, 2013 were going to be waived by its lending group. However, in June 2014, the Company was advised that certain non-majority participants in the Company's note payable did not waive their right to call the Company's note payable due to the financial covenant failures as of December 31, 2013. Accordingly, the note payable balance has been reclassified as a current liability as of December 31, 2013. The reclassification is a non-cash adjustment and will have no impact on the Company’s cash flows. On June 9, 2014 the Company completed its assessment of the impact of the reclassification of the current maturities of long-term debt as of December 31, 2013 and believes the effects of the restatement are as summarized in the following tables:

Consolidated Balance Sheet as of December 31, 2013

	Previously Reported			Adjustment			As Restated
Oil and natural gas properties, full cost method, net of accumulated depletion	$	23,971		$	(371	)	$	23,600
Total oil and natural gas properties and other equipment, net	$	24,441		$	(371	)	$	24,070
Total assets	$	26,201		$	(371	)	$	25,830
Current maturities of notes payable	$	387		$	17,125		$	17,512
Total current liabilities	$	2,239		$	17,125		$	19,364
Notes payable	$	17,181		$	(17,125	)	$	56
Total long-term liabilities	$	20,547		$	(17,125	)	$	3,422
Accumulated deficit	$	(42,201	)	$	(371	)	$	(42,572	)
Total shareholders’ equity	$	3,415		$	(371	)	$	3,044
Total liabilities and shareholders’ equity	$	26,201		$	(371	)	$	25,830

Consolidated Balance Sheet as of December 31, 2012

	Previously Reported			Adjustment			As Restated
Oil and natural gas properties, full cost method, net of accumulated depletion	$	22,745		$	(239	)	$	22,506
Total oil and natural gas properties and other equipment, net	$	23,312		$	(239	)	$	23,073
Total assets	$	24,667		$	(239	)	$	24,428
Accumulated deficit	$	(38,280	)	$	(239	)	$	(38,519	)
Total shareholders’ equity	$	5,632		$	(239	)	$	5,393
Total liabilities and shareholders’ equity	$	24,667		$	(239	)	$	24,428

Consolidated Statement of Operations for the Year Ended December 31, 2013

	Previously Reported			Adjustment			As Restated
Depreciation, depletion and amortization	$	572		$	132		$	704
Total expenses	$	6,893		$	132		$	7,025
Operating income (loss)	$	(3,271	)	$	(132	)	$	(3,403	)
Net income (loss)	$	(3,921	)	$	(132	)	$	(4,053	)
Net income (loss) per basic common share	$	(0.17	)	$	(0.01	)	$	(0.18	)
Net income (loss) per diluted common share	$	(0.17	)	$	(0.01	)	$	(0.18	)

Consolidated Statement of Operations for the Year Ended December 31, 2012

	Previously Reported		Adjustment			As Restated
Depreciation, depletion and amortization	$	542	$	118		$	660
Total expenses	$	4,599	$	118		$	4,717
Operating income (loss)	$	1,909	$	(118	)	$	1,791
Net income (loss)	$	1,154	$	(118	)	$	1,036
Net income (loss) per basic common share	$	0.05	$	(0.00	)	$	0.05
Net income (loss) per diluted common share	$	0.05	$	(0.00	)	$	0.05

F-8

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

2.	Organization and nature of operations

Prior to May 9, 2013, Claimsnet.com, Inc.’s (“Claimsnet”) 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, Claimsnet acquired a majority interest in TransCoastal Corporation (“TransCoastal”), a Texas corporation through an Acquisition Agreement. Claimsnet issued a total of 3,721,036 shares of Series F Preferred Stock, with an additional 194,920 Series F Preferred Stock to be issued, in consideration for the common stock of TransCoastal. Each share of Series F 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 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.

Claimsnet acquired TransCoastal under the an acquisition agreement (the “Acquisition Agreement”), dated March 18, 2013, as amended by the Amended Acquisition Agreement, dated April 24, 2013, through the issuance of shares of our convertible Series F preferred stock. This resulted in the owners of TransCoastal (the “accounting acquirer”) having actual or effective operating control of Claimsnet after the transaction, with the shareholders of Claimsnet (the “legal acquirer”) continuing only as passive investors. TransCoastal is an oil and gas exploration and production company focused primarily in the development of oil and gas reserves in Texas and the Southwest region of the United States. Effective on the date of acquisition, TransCoastal became a Delaware Corporation. TransCoastal, and its wholly owned subsidiary, CoreTerra Operating, LLC (“CTO”), are referred to as the “Company”.

Pursuant to the Amended Acquisition Agreement, on June 27, 2013, the Company placed, at the time of closing of the acquisition, all of the assets and liabilities constituting the current non-oil and gas assets of our business operations into a separate wholly-owned subsidiary of the Company, ANC Holdings, Inc. (“ANC Holdings”), and sold that subsidiary to certain debt holders of the Company, who were affiliates of Claimsnet, in consideration for cancellation by such debt holders of the Company indebtedness owed to them.

Additionally, during the year ended December 31, 2013, TransCoastal Partners LLC, an entity under common control of the Company, contributed all of its net assets and liabilities, which approximated $700 at the date of contribution, to the Company. The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) and are presented in accordance with Accounting Standard Codification (“ASC”) 805, Business Combinations , which requires that entities under common control be reflected at their historical cost. Accordingly, the accompanying consolidated financial statements reflect the historical combined results of the common controlled entity prior to the reverse recapitalization date.

Claimsnet formally changed its name to TransCoastal Corporation and declared a reverse 200 to 1 stock split effective July 1, 2013.

3.	Going concern consideration

The consolidated financial statements have been prepared assuming the Company will continue as a going concern. As of December 31, 2013, the Company had a working capital deficit of approximately $18,476, and an accumulated deficit of approximately $42,572. For the year ended December 31, 2013, the Company had a net loss of approximately $4,053 and used cash in operations of approximately $1,654. The working capital deficit at December 31, 2013 is primarily the result of increased aged accounts payable and accrued liabilities due to a reduction in available cash to pay third party vendors, the Company's long term debt being current, and the liability related to the arbitration settlement discussed in Note 13. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. During the year ended December 31, 2013, the Company entered into an investment agreement (the “Investment Agreement”) with a third party which allows the Company to put common shares to the third party for an aggregate purchase price up to $5,000.

F-9

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

3.	Going concern consideration (continued)

If the Company wishes to act upon this agreement the Company will need to register the necessary shares specified in the agreement within a registration statement with the SEC. As of March 31, 2014, and through the date of this report, the Company has not decided to act upon this agreement, if the company chose to act upon the agreement it would require an S-1 Registration Statement to be filed and deemed effective by the SEC. If the Company is unable to obtain this additional equity financing, it may require the Company to liquidate a portion of its oil and natural gas properties to meet its liquidity needs, which could affect the Company’s long-term strategic plan and require the Company to liquidate certain oil and natural gas properties at an amount less than would normally be achieved if sold in the ordinary course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

4.	Summary of significant accounting policies

Basis of Presentation

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America.

These consolidated financial statements were approved by management and available for issuance on March 31, 2014. Subsequent events have been evaluated through this date.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of TransCoastal and its wholly owned subsidiary, CTO. All intercompany transactions and balances have been eliminated in consolidation.

Fair Value Measurements

The Company has adopted and follows ASC 820, Fair Value Measurements and Disclosures , for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC 820 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by ASC 820 are:

Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 — Inputs (other than quoted market prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Valuation of instruments includes unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities.

F-10

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

4.	Summary of significant accounting policies (continued)

Fair Value Measurements (continued)

As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date. The carrying amounts of the Company’s financial assets and liabilities, such as cash and cash equivalents, oil and natural gas sales receivable, and accounts payable and accrued liabilities, approximate their fair values because of the short maturity of these instruments.

Cash and Cash Equivalents

The Company considers all highly-liquid debt instruments with original maturities of three months or less to be cash equivalents. As of December 31, 2013 and 2012, the Company held approximately $63 and $16, respectively, in cash equivalents.

The Company maintains its cash balances in financial institutions which are insured by the Federal Deposit Insurance Corporation (“FDIC”). The interest bearing cash accounts maintain FDIC coverage of up to $250 per institution. At December 31, 2012, non-interest bearing accounts are fully covered subject to the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”). This provision of the Act is scheduled to expire after December 31, 2012 at which point in time the FDIC coverage for all accounts returns to $250 per institution. As of December 31, 2013 and 2012, the Company had $44 and $0, respectively, in excess of its FDIC coverage.

Accounts Receivable

Accounts receivable is comprised of billings for services as the operator on certain wells, that TransCoastal has no working interest in, and accrued natural gas and crude oil sales. The Company performs ongoing credit evaluations of its customers’ and extends credit to virtually all of its customers. Credit losses to date have not been significant and have been within management’s expectations. In the event of complete non-performance by the Company’s customers, the maximum exposure to the Company is the outstanding accounts receivable, net balance at the date of non-performance. The amounts billed to third parties for services as the operator have rights of offset against revenues generated from the sale of oil and gas commodities. For the years ended December 31, 2013 and 2012, the Company had no bad debt expense.

Derivative Activities

The Company utilized oil and natural gas derivative contracts to mitigate it’s exposure to commodity price risk associated with its future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors or collars. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company does not apply hedge accounting to its oil and natural gas derivative contracts and accordingly the changes in the fair value of these instruments are recognized in the consolidated statements of operations in the period of change.

The Company’s derivative instruments are issued to manage the price risk attributable to our expected natural gas and oil production. While there is risk that the financial benefit of rising natural gas and oil prices may not be captured, Company management believes the benefits of stable and predictable cash flow are more important. Every unsettled derivative instrument is recorded on the accompanying consolidated balance sheets as either an asset or a liability measured at its fair value.

F-11

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

4.	Summary of significant accounting policies (continued)

Derivative Activities (continued)

Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from natural gas and oil derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

Realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative gains or (losses) in the accompanying consolidated statements of operations.

Oil and Gas Natural Gas Properties

The Company uses the full-cost method of accounting for its oil and natural gas producing activities as further defined under ASC 932, Extractive Activities - Oil and natural gas . Under these provisions, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits and other internal costs directly identified with these activities, and oil and natural gas property acquisitions are capitalized. All costs related to production, general corporate overhead or similar activities are expensed as incurred.

Proved properties are amortized using the units of production method (“UOP”). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced at year end by the cost of those reserves.

The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs (future costs to access and develop reserves) and asset retirement costs that are not already included in oil and natural gas property, less related salvage value.

The cost of unproved properties and properties under development are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed in service. Geological and geophysical costs not associated with specific properties are recorded to proved properties. Unproved properties and properties under development are reviewed for impairment at least quarterly. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. As of December 31, 2013 and 2012, no unproved properties or properties under development were included in the oil and natural gas properties of the accompanying consolidated financial statements.

Proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities in a particular country are sold, in which case a gain or loss is recognized in income. For the years ended December 31, 2013 and 2012, no gain or loss from the sale or disposition of oil and natural gas properties occurred.

Under the full-cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10 percent per annum based on industry standards and adjusted for cash flow hedges. Estimated future net cash flows exclude future cash outflows associated with settling accrued asset retirement obligations. Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the accompanying consolidated statements of operations. For the years ended December 31, 2013 and 2012, no impairment charge occurred.

F-12

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

4.	Summary of significant accounting policies (continued)

Oil and Gas Natural Gas Properties (continued)

During the years ended December 31, 2013 and 2012, the Company determined $31 and $111, respectively, of interest costs were incurred during the development period of our wells, which is reflected as an increase to the Company’s full-cost pool in the accompanying consolidated balance sheets.

Other Property and Equipment

Other property and equipment, which includes buildings, field equipment, vehicles, and office equipment, is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Vehicles and office equipment are generally depreciated over a useful life of five or six years, field equipment is generally depreciated over a useful life of ten years and buildings are generally depreciated over a useful life of twenty years.

Impairment of Long-Lived Assets

The Company assesses the impairment of long-lived assets when circumstances indicate that the carrying value may not be recoverable. The Company determines if impairment has occurred through adverse changes. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. For the years ended December 31, 2013 and 2012, no circumstances indicated an unrecoverable carrying value of the long-lived assets.

Goodwill

Goodwill was generated as part of the CTO acquisition during the year ended December 31, 2011 and represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition. Goodwill is not amortized; rather, it is tested for impairment annually and when events or changes in circumstances indicate that fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. As of December 31, 2013 and 2012, the Company had only one reporting unit. To assess impairment, the Company has the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the book value. Absent a qualitative assessment, or, through the qualitative assessment, if the Company determines it is more likely than not that the fair value of the reporting unit is less than the book value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the book value, the recorded goodwill is impaired to its implied fair value with a charge to operating expenses. For the years ended December 31, 2013 and 2012, no impairment charge occurred.

Deferred Equity Issuance Costs

The Company complies with the requirements of the SEC Staff Accounting Bulletin (SAB) Topic 5A ““Expenses of Offering’’. Deferred equity issuance costs consist principally of fees incurred through the consolidated balance sheet dates that are related to an equity issuance and that will be charged to stockholders’ equity upon the receipt of the equity proceeds or charged to expense if the equity offering is not completed. During the year ended December 31, 2013 and 2012, the Company incurred deferred equity issuance costs of approximately $265 and $0, respectively. The deferred equity issuance costs are included in other non-current assets in the consolidated balance sheets. Additionally, these costs are reviewed periodically by management for indications of impairment. For the year ended December 31, 2013, the Company did not have an impairment charge.

F-13

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

4.	Summary of significant accounting policies (continued)

Asset Retirement Obligations

The Company follows the provisions of ASC 410-20, Asset Retirement Obligations . ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted as part of the oil and natural gas property. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company’s asset retirement obligations relate to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties.

Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under ASC 820. Additionally, because of the subjectivity of assumptions and the relatively long lives of the Company’s wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.

Revenue Recognition and Natural Gas Imbalances

The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells. The Company will also enter into physical contract sale agreements through its normal operations. These contracts are not considered derivative contracts by the Company in accordance with the normal purchases and normal sales provision of ASC 815-10-15.

Gas imbalances are accounted for using the sales method. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. However, the Company has no history of significant gas imbalances.

Drilling Revenue

The Company follows the provisions of ASC 605-45, Revenue Recognition – Principal Agent Considerations , which requires the Company to record drilling revenues at net given such services are on behalf of third party oil and natural gas property operators. The Company does not own a participating interest in the wells for which drilling revenues, net are recorded.

During the year ended December 31, 2013 and 2012, the Company recognized net drilling revenues of approximately $0 and $2,746, respectively, which are included in the accompanying consolidated statements of operations. The following table presents the gross drilling revenues and drilling expenses of the Company for the year ended December 31, 2012:

Gross drilling revenues	$	11,446
Gross drilling expenses		(8,700	)

Total drilling revenues, net	$	2,746

F-14

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

4.	Summary of significant accounting policies (continued)

Loss on turn-key contracts

During the year ended December 31, 2013, the Company was involved in an arbitration case regarding the drilling, completion and operation of wells on behalf of third party oil and natural gas property operators. In March of 2014, the arbitrator for this case awarded a final award amount of approximately $580 to the third party oil and natural gas operator due from the Company, which is included in the accounts payable and accrued liabilities of the accompanying consolidated balance sheet at December 31, 2013. Additionally, during the year ended December 31, 2013, the Company incurred drilling, completion and operating costs under these turn-key contracts, which reimbursement was deemed to be uncollectible due to the outcome of the arbitration. These uncollectable turn-key contract expenses approximated $888 during the year ended December 31, 2013, and are reflected in the loss on turn-key contracts in the accompanying consolidated statement of operations.

Lease Operating Expenses

Lease operating expenses represents severance and production taxes, field personnel salaries, saltwater disposal, ad valorem taxes, repairs and maintenance, and other operating expenses. Lease operating expenses are expensed as incurred.

Sales-Based Taxes

The Company incurs severance tax on the sale of its production which is generated in Texas. These taxes are reported on a gross basis and are included in lease operating expenses within the accompanying consolidated statements of operations. Sales-based taxes for the years ended December 31, 2013 and 2012 were approximately $199 and $177, respectively.

Income Taxes

The Company complies with GAAP which requires an asset and liability approach to financial reporting for income taxes. Deferred income tax assets and liabilities are computed for differences between the financial statement and tax basis of assets and liabilities that will result in future taxable or deductible amounts, based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established, when necessary, to reduce deferred income tax assets to the amount expected to be realized.

The Company is required to determine whether its tax positions are more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The tax benefit recognized is measured as the largest amount of benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement with the relevant taxing authority. De-recognition of a tax benefit previously recognized results in the Company recording a tax liability that reduces ending retained earnings. Based on its analysis, the Company has determined that it has not incurred any liability for unrecognized tax benefits as of December 31, 2013 and 2012.

The Company’s conclusions may be subject to review and adjustment at a later date based on factors including, but not limited to, on-going analyses of and changes to tax laws, regulations and interpretations thereof. The Company recognizes interest and penalties related to unrecognized tax benefits in interest expense and other expenses, respectively. No interest expense or penalties have been recognized as of December 31, 2013 and 2012 and for the years then ended.

F-15

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

4.	Summary of significant accounting policies (continued)

Income Taxes (continued)

The Company files an income tax return in the U.S. federal jurisdiction, and may file income tax returns in various U.S. states and foreign jurisdictions. Generally, the Company is subject to income tax examinations by major taxing authorities since 2010.

The Company may be subject to potential examination by U.S. federal, U.S. states or foreign jurisdiction authorities in the areas of income taxes. These potential examinations may include questioning the timing and amount of deductions, the nexus of income among various tax jurisdictions and compliance with U.S. federal, U.S. state and foreign tax laws. The Company’s management does not expect that the total amount of unrecognized tax benefits will materially change over the next twelve months.

Net Income (Loss) Per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to shareholders by the weighted average number of common shares outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from convertible preferred stock and warrants. For the year ended December 31, 2013, there were 1,374,500 potentially dilutive shares considered in the diluted weighted average common shares. For the year ended December 31, 2012, there were 75,000 potentially dilutive shares.

Stock-Based Compensation

The Company accounts for stock-based compensation in accordance with ASC 718, Compensation – Stock Compensation . The standard requires the measurement and recognition of compensation expense in the Company’s consolidated statements of operations for all share-based payment awards made to the Company’s employees, directors and consultants including employee stock options, non-vested equity stock and equity stock units, and employee stock purchase grants. Stock-based compensation expense is measured at the grant date, based on the estimated fair value of the award, reduced by an estimate of the annualized rate of expected forfeitures, and is recognized as an expense over the employees’ expected requisite service period, generally using the straight-line method. In addition, ASC 718 requires the benefits of tax deductions in excess of recognized compensation expense to be reported as a financing cash flow, rather than as an operating cash flow as prescribed under previous accounting rules.

The Company’s forfeiture rate represents the historical rate at which the Company’s stock-based awards were surrendered prior to vesting. ASC 718 requires forfeitures to be estimated at the time of grant and revised on a cumulative basis, if necessary, in subsequent periods if actual forfeitures differ from those estimates.

During the year ended December 31, 2013 and 2012, the Company incurred a stock based compensation expense of approximately $270 and $213, respectively, related to stock grant issuances and is included in the accompanying consolidated statement of operations in general and administrative expenses.

F-16

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

4.	Summary of significant accounting policies (continued)

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Additionally, the Company’s estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.

Recent Accounting Pronouncements

In January 2013, the Financial Accounting Standards Board (“FASB”) issued ASC Update No. 2013-01 (“ASC No. 2013-01”). The objective of ASC No. 2013-01 is to clarify that the scope of Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities (“ASC No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. ASC No. 2011-11, issued in December 2011, requires that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. The Company adopted ASC No. 2013-01 effective January 1, 2013, and it did not have an effect on the Company’s consolidated financial statements.

F-17

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

5.	Fair value measurements

The following table presents information about the Company’s assets and liabilities measured at fair value as of December 31, 2013:

	Level 1		Level 2		Level 3		Balance as of December 31, 2013
Assets (at fair value):
Money market mutual fund	$	63	$		$		$	63

Liabilities (at fair value):
Derivative liabilities	$		$	143	$		$	143
Asset retirement obligations						959		959
Total liabilities (at fair value)	$		$	143	$	959	$	1,102

The following table presents information about the Company’s assets and liabilities measured at fair value as of December 31, 2012:

	Level 1		Level 2		Level 3		Balance as of December 31, 2012
Assets (at fair value):
Money market mutual fund	$	16	$		$		$	16
Derivative assets				28				28
Total assets (at fair value)	$	16	$	28	$		$	44

Liabilities (at fair value):
Derivative liabilities	$		$	6	$		$	6
Asset retirement obligations						877		877
Total liabilities (at fair value)	$		$	6	$	877	$	883

F-18

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

6.	Oil and natural gas properties

The following tables present a summary of the Company’s oil and natural gas properties at December 31, 2013 and 2012:

	2013			2012

Proved-developed producing properties	$	6,424		$	4,960
Proved-developed non producing properties		9,534			9,509
Proved-undeveloped properties		9,972			9,850
Less: Accumulated depletion		(2,330	)		(1,813	)

Total oil and natural gas properties, net of accumulated depletion	$	23,600		$	22,506

On October 29, 2012, the Company obtained 100% of the working interests and 75% of the revenue interests of wells located in Gray County, Texas as settlement for notes receivable, related parties issued on March 31, 2012 and June 30, 2012 for approximately $1,477. The following table presents a summary of the assets and liabilities obtained:

Value of assets and liabilities obtained	$	1,488
Proved oil and natural gas properties
Asset retirement obligations		(11	)

Total assets and liabilities obtained	$	1,477

Effective May 2013 through August 2013, TransCoastal entered into purchase agreements with several entities and individuals to acquire various oil and natural gas properties, which include working interests ranging from 0.247% to 100%, and net revenue interests ranging from 0.186% to 81.25% in multiple counties of Texas and Louisiana, for a total consideration of approximately $859. The purchase price was derived based on the cash consideration paid directly by the Company and debt financing, along with the issuance of common stock and warrants at fair value. The following table presents a summary of the fair value of assets and liabilities acquired in accordance with ASC 805-10, Business Combinations :

Fair value of assets acquired and liabilities assumed
Proved-developed producing properties	$	876
Asset retirement obligation		(17	)
Total fair value of assets acquired and liabilities assumed, net	$	859

Consideration transferred
Cash consideration paid directly by the Company	$	140
Cash consideration paid through debt financing		322
Stock to be issued at fair value		397
Total consideration paid	$	859

F-19

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

7.	Other property and equipment

The following table presents a summary of the Company’s other property and equipment at December 31, 2013 and 2012:

	2013			2012

Field equipment	$	322		$	322
Vehicles		512			422
Office equipment		245			245
Buildings		130			130
Land		14			14
Less: Accumulated depreciation		(753	)		(566	)
Total other property and equipment, net of accumulated depreciation	$	470		$	567

8.	Asset retirement obligations

The Company has recognized the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties. The present value of the estimated asset retirement obligations has been capitalized as part of the carrying amount of the related oil and natural gas properties. The liability has been accreted to its present value as of the end of each period. At December 31, 2013 and 2012, the Company evaluated 218 and 213 wells, and has determined a range of abandonment dates between December 2012 and December 2051. The following table represents a reconciliation of the asset retirement obligations for the years ended December 31, 2013 and 2012:

	2013		2012

Asset retirement obligations, start of year	$	877	$	838
Additions to asset retirement obligation		37		1
Accretion of discount		45		38
Asset retirement obligations, end of year	$	959	$	877

9.	Notes payable

On May 19, 2011, as amended from time to time through February 12, 2014, the Company entered into a loan agreement (the “Agreement”) with Green Bank with an initial borrowing base of $15,000,000 and amended to $16,950,000 on February 12, 2014. The Agreement bears interest at the prime rate minus 0.5%, but not less than 4.5%. Interest payments are due monthly with all principal and any unpaid interest being due on June 1, 2015. The interest rate was 4.5% at December 31, 2013 and 2012. Additionally, in accordance with the Agreement, for the period from March 1, 2012 through September 30, 2012, monthly borrowing base reductions of $125 occurred automatically on the first day of each month. Effective October 1, 2012, the monthly borrowing base reduction increased to $150 through January 15, 2013. The monthly borrowing base reductions were amended to $0 on February 11, 2013. On February 12, 2014, the monthly borrowing base reductions were amended to $125 payable on the first of each month for the period of March 1, 2014 through May 1, 2014.

F-20

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

9.	Notes payable (continued)

The Agreement is collateralized by essentially all of the oil and natural gas related assets of the Company, contains personal guarantees from the principal officers, and requires compliance with certain financials covenants including, among others: (1) a requirement to maintain a current ratio of not less than 1.0 to 1.0; (2) a maximum permitted ratio of total liabilities to tangible net worth of not more than 2.0 to 1.0; and (3) a requirement to maintain a ratio of EBITDAX, as defined by the Agreement, to interest expense of not less than (a) 3.00 to 1.00 for all fiscal quarters prior to December 31, 2011, (b) 3.25 to 1.00 for the fiscal quarter ending March 31, 2012, and (c) 3.50 to 1.00 for all fiscal quarters ending on or after June 30, 2012. As of December 31, 2013, the Company was not in compliance with its current ratio. Accordingly, the balance as of December 31, 2013 is classified as current. The Company was in compliance with all financial covenants as of December 31, 2012.

As of December 31, 2013 and 2012, the Company had an outstanding principal balance due to Green Bank of approximately $17,500 and $15,400, respectively. As of December 31, 2013 and 2012, the current maturities of the outstanding principal balance were approximately $375 and $150, respectively.

Additionally, on October 21, 2013, the Company entered into a vehicle loan agreement (“Car Note”) with Western Equipment Finance, Inc. for a total borrowing base of $74. The Car Note bears interest at an approximate rate of 9%. Interest and principal payments are due monthly with any unpaid principal and interest due on August 18, 2018. As of December 31, 2013, the Company had an outstanding principal balanced due to Western Equipment Finance, Inc. of approximately $68. As of December 31, 2013, the current maturities of the outstanding principal balance were approximately $12.

10.

Deferred income taxes

For the years ended December 31, 2013 and 2012, the Company estimated no current or deferred tax provisions. A reconciliation of income tax expense (benefit) computed by applying the U.S. federal statutory income tax rate and the reported effective tax rate on income for the years ended December 31, 2013 and 2012 are as follows:

	2013			2012
Income tax provision calculated using the federal statutory income tax rate	$	(1,378	)	$	352
State income taxes, net of federal income taxes
Permanent differences and other		2
Change in valuation allowance		1,376			(352	)

Total income tax expense	$			$

F-21

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

10.

Deferred income taxes (continued)

Deferred tax assets are determined based on the difference between financial statement and tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The components of the deferred taxes as of December 31, 2013 and 2012 are as follows:

	2013			2012
Deferred tax assets
Federal net operating loss carryforward	$	3,056		$	1,697
Accrued interest
Asset retirement obligations		326			298
Shares to be issued
Total deferred tax assets		3,382			1,995

Deferred tax liabilities
Depletion and Depreciation		242			231

Net deferred tax asset, before valuation allowance		3,140			1,764
Valuation allowance		(3,140	)		(1,764	)

Net deferred tax asset	$			$

As of December 31, 2013 and 2012, the Company had net operating loss (“NOL”) carryforwards of approximately $8,686 and $4,820, respectively, which can be utilized in future years. These NOLs, if not used, will expire between 2025 and 2033. A valuation allowance has been established for the full amount of the tax asset since it is more likely than not that the deferred tax asset will not be realized.

11.

Shareholders’ equity

Reverse Recapitalization

Claimsnet acquired TransCoastal under the Acquisition Agreement, dated March 18, 2013, (as amended by the Amended Acquisition Agreement, dated April 24, 2013), through the issuance of shares of Claimsnet’s convertible preferred stock. Pursuant to the Amended Acquisition Agreement, on June 27, 2013 the Company placed all of the assets and liabilities constituting the current non-oil and gas assets of the Company into a separate wholly-owned subsidiary of the Company, ANC Holdings. ANC Holdings was then sold to certain affiliated debt holders of the Company, in consideration for cancelling the indebtedness owed. Additionally, on July 30, 2013 the Board of Directors, after receiving approval of the corporate action by FINRA, authorized the completion of the two hundred to one (200 to 1) reverse stock split of the issued and outstanding Common Stock, as may be adjusted (the “ Reverse Stock Split”), that reduced the outstanding shares of Common Stock from 35,644,696 to approximately 178,224 shares (recognizing that any resulting fractional shares will be rounded up to result in a maximum aggregate 178,250 post-split shares) and changed the name of the Company to TransCoastal Corporation. On July 30, 2013 the Board of Directors of the Company also authorized the issuance of Common Stock share certificates of the Company to all the Series F Preferred Stockholders converting the Company's Series F preferred shares into Common Stock of the Company.

F-22

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

11.

Shareholders’ equity (continued)

Stock Issuances

During the year ended December 31, 2013 and 2012, the Company issued 206,250 and 37,500 shares, respectively, of Series A convertible preferred stock at 8%, payable annually, for $679 and $75, respectively. The Series A preferred stock may be converted any time after the first year at the request of the shareholder or the Company into two (2) shares of common stock of TransCoastal and one (1) warrant that will allow the holder, for a period of three years from the date of issue, to acquire one additional share of TransCoastal common stock for each warrant at a purchase price of $3.50 per share. The Series A preferred stock issued in 2013 resulted in a beneficial conversion feature at the date of issuance. As a result, a constructive dividend on the Series A preferred stock of approximately $266 is reflected in the accompanying consolidated statements of changes in shareholders’ equity. All of the Series A preferred shares were converted into common stock during the year ended December 31, 2013. Prior to conversion, the Company paid approximately $39 of cash dividends to the Series A preferred shareholders.

During the year ended December 31, 2013, the Company issued 687,250 of Series G convertible preferred stock at 8%, payable annually, for $684. The preferred stock may be converted any time after the first year at the request of the shareholder or the Company into two (2) shares of common stock of TransCoastal and two (2) warrants that will allow the holder, for a period of two years from the date of issue, to acquire one additional share of TransCoastal common stock for each warrant at a purchase price of $3.75 per share. The Series G preferred stock issued in 2013 resulted in a beneficial conversion feature at the date of issuance. As a result, a constructive dividend on the Series G preferred stock of approximately $1,756 is reflected in the accompanying consolidated statements of changes in shareholders’ equity.

During the year ended December 31, 2013, the Company entered into an investment agreement with a third party which allows the Company to put common shares to the third party for an aggregate purchase price up to $5,000. The purchase price of the third party would be equal to 75% of the lowest daily closing bid price of the Company’s common stock during the pricing period. The pricing period is represented by the five trading days immediately following the date on which the Company provides written notice to the third party of its requested investment. In order to facilitate the execution of this investment agreement, the Company paid the third party $15 in cash and issued 256,578 shares of its common stock valued at $250. As of December 31, 2013, the total consideration of $265 is included other non-current assets in the accompanying consolidated balance sheets.

Stock Issuances for Services

During the year ended December 31, 2013, the Company issued 207,467 common shares to certain employees for services to the Company. The Company valued those services at approximately $270.

During the year ended December 31, 2012, the Company issued 80,913 Series F preferred shares, with another 18,415 Series F preferred shares to be issued, to certain employees and vendors for services to the Company. The Company valued those services at approximately $215.

During the year ended December 31, 2012, the shareholders’ due the $1,350 of stock based compensation, in the form of Series F preferred shares, forfeited their right to the shares, which is reflected as additional paid–in capital the accompanying consolidated statements of changes in shareholders’ equity.

F-23

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

11.

Shareholders’ equity (continued)

Stock Issued as of December 31, 2013 and 2012

At December 31, 2013 and 2012, the authorized capital stock of the Company consisted of 250,000,000 shares of voting common stock with a par value of $0.001 per share and 25,000,000 shares of preferred stock with a par value of $0.001 per share. As of December 31, 2013 and 2012, there were 22,453,773 and 0, respectively, common shares issued and outstanding, 0 and 37,500, respectively, Series A preferred shares issued and outstanding, 0 and 3,721,036, respectively, Series F preferred shares issued and outstanding, and 687,500 and 0, respectively, Series G preferred shares issued and outstanding. Additionally, at December 31, 2013 and 2012, there were 265,625 and 0, respectively, common shares to be issued and 165,105 and 194,920, respectively, Series F preferred shares to be issued. As of December 31, 2013 and 2012, the total long-term liability for stock to be issued was approximately $2,496 and $2,091, respectively, which is included in the accompanying consolidated balance sheets.

12.

Derivative contracts, at fair value

In the normal course of business, the Company utilizes derivative contracts in connection with its oil and natural gas operations. Derivative contracts are subject to additional risks that can result in additional losses. The Company’s derivative activities and exposure to derivative contracts are classified by the following primary underlying risk: commodity price. In addition to its primary underlying risk, the Company is also subject to additional counterparty risk due to inability of its counterparties to meet the terms of their contracts.

Options

The Company is subject to commodity price risk in the normal course of pursuing its investment objectives. The Company may enter into options to speculate on the price movements of the commodity underlying the option or for use as an economic hedge against oil and natural gas production.

Option contracts purchased give the Company the right, but not the obligation, to buy or sell within a limited time, a commodity at a contracted price that may also be settled in cash, based on differentials between specified indices or prices. For some OTC options, the Company may be exposed to counterparty risk from the potential that a seller of an option contract does not sell or purchase the underlying asset as agreed under the terms of the option contract. The maximum risk of loss from counterparty risk to the Company is the fair value of the contracts and the premiums paid to purchase its open option contracts. In these instances, the Company considers the credit risk of the intermediary counterparty to its option transactions in evaluating potential credit risk.

Swap Contracts

Generally, a swap contract is an agreement that obligates two parties to exchange a series of cash flows at specified intervals based upon or calculated by reference to changes in specified prices or rates for a specified notional amount of the underlying assets. The payment flows are usually netted against each other, with the difference being paid by one party to the other. During the term of the swap contracts, changes in value are recognized as unrealized gains or losses by marking the contracts at fair value. Additionally, the Company records a realized gain (loss) when a swap contract is terminated and when periodic payments are received or made at the end of each measurement period. The fair value of open swaps reported in the balance sheet may differ from that which would be realized in the event the Company terminated its position in the contracts. Risks may arise as a result of the failure of the counterparty to the swap contract to comply with the terms of the swap contract.

F-24

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

12.

Derivative contracts, at fair value (continued)

The loss incurred by the failure of a counterparty is generally limited to the aggregate fair value of swap contracts in an unrealized gain position as well as any collateral posted with the counterparty. The risk is mitigated by having a master netting arrangement between the Company and the counterparty and by the posting of collateral by the counterparty to the Company to cover the Company’s exposure to the counterparty. Therefore, the Company considers the creditworthiness of each counterparty to a swap contract in evaluating potential credit risk.

Underlying Exposure

At December 31, 2013, the volume of the Company’s derivative activities based on their notional amounts and number of contracts, categorized by primary underlying risk, are as follows:

	Long Exposure				Short Exposure
Primary underlying risk	Notional Amounts ^(a)		Number of Contracts ^(b)		Notional Amounts ^(a)		Number of Contracts ^(b)
Commodity price
Swap	$				$	3,111		4
Options		354		1		266		1
	$	354		1	$	3,377		5

(a)

Notional amounts presented for contracts are based on the fair value of the underlying commodity as if the contracts were exercised at December 31, 2013.

(b)

Number of contracts is presented in whole numbers.

At December 31, 2012, the volume of the Company’s derivative activities based on their notional amounts and number of contracts, categorized by primary underlying risk, are as follows:

	Long Exposure				Short Exposure
Primary underlying risk	Notional Amounts ^(c)		Number of Contracts ^(d)		Notional Amounts ^(c)		Number of Contracts ^(d)
Commodity price
Swap	$				$	2,751		2
Options		354		1		266		1
	$	354		1	$	3,017		3

(c)

Notional amounts presented for contracts are based on the fair value of the underlying commodity as if the contracts were exercised at December 31, 2012.

(d)

Number of contracts is presented in whole numbers.

F-25

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

12.

Derivative contracts, at fair value (continued)

Impact of Derivatives on the Consolidated Balance Sheets and Consolidated Statements of Operations

The following table identifies the fair value amounts of derivative instruments included in the accompanying consolidated balance sheet as derivative assets and derivative liabilities, categorized by primary underlying risk, at December 31, 2013. Balances are presented on a gross basis, prior to the application of the impact of counterparty and collateral netting.

	Derivative Assets		Derivative Liabilities			Amount of gain (loss)
Primary underlying risk
Commodity price
Swaps	$		$	(135	)	$	(261	)
Options		1		(9	)		(8	)
Gross total		1		(144	)		(269	)
Less: Master netting arrangements		1		(1	)
Total	$		$	(143	)	$	(269	)

Balances are presented on a gross basis, prior to the application of the impact of counterparty and collateral netting.

	Derivative Assets		Derivative Liabilities			Amount of gain (loss)
Primary underlying risk
Commodity price
Swaps	$	32	$			$	42
Options		16		(26	)		(260	)
Gross total		48		(26	)		(218	)
Less: Master netting arrangements		26		(26	)
Total	$	22	$			$	(218	)

F-26

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

12.

Derivative contracts, at fair value (continued)

The following table identifies the net gain and (loss) amounts included in the accompanying consolidated statement of operations as derivative losses for the year ended December 31, 2013.

	Realized gain (loss)			Unrealized gain (loss)			Total
Primary underlying risk
Commodity price
Swaps	$	(104	)	$	(157	)	$	(261	)
Options					(8	)		(8	)
Total	$	(104	)	$	(165	)	$	(269	)

The following table identifies the net gain and (loss) amounts included in the accompanying consolidated statement of operations as derivative losses for the year ended December 31, 2012.

	Realized gain (loss) ^(e)			Unrealized gain (loss)		Total
Primary underlying risk
Commodity price
Swaps	$	21		$	21	$	42
Options		(342	)		82		(260	)
Total	$	(321	)	$	103	$	(218	)

(e)

Realized gain (loss) includes approximately $336 of realized losses on expired derivative options acquired prior to January 1, 2012.

13.

Related party transactions

F-27

TRANSCOASTAL CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(AMOUNTS SHOWN IN THOUSANDS EXCEPT SHARE AND PER SHARE INFORMATION)

14.

Commitments and contingencies

Oil and Natural Gas Regulations

The Company is subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes that it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, environmental matters are subject to regulation by various federal and state agencies.

Legal Proceedings

The Company is subject to various legal proceedings and claims that arise in the ordinary course of business. During the year ended December 31, 2013, the Company was involved in an arbitration case regarding the drilling, completion and operation of wells on behalf of third party oil and natural gas property operators. In March 2014, the arbitrator for this case awarded a final award amount of approximately $580 to the third party oil and natural gas operator due from the Company, which is included in the accounts payable and accrued liabilities of the accompanying consolidated balance sheet at December 31, 2013.

Lease Commitments

The Company leases its primary office space under an operating lease which expires in 2014. Lease expense was approximately $193 and $189, respectively, for the years ended December 31, 2013 and 2012. Aggregate future minimum annual rental payments are $181.

15.

Risk concentrations

For the years ended December 31, 2013 and 2012, revenues from the Company’s 44 and 33, respectively, producing leases 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, respectively, purchasers. 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.

F-28

SUPPLEMENTAL INFORMATION

Presented in accordance with

FASB ASC Topic 932, Extractive Activities - Oil and Gas

F-29

TRANSCOASTAL CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(AMOUNTS SHOWN IN THOUSANDS)

Restatement of previously issued supplemental oil and natural gas disclosures (Unaudited)

The Company has restated certain amounts reported as of December 31, 2013 and 2012, and for each of the years in the two year period ended December 31, 2013. The restatement reflects changes in reserve estimates for each of the years in the two year period ended December 31, 2013, which were included in the Company’s Annul Report on Form 10K.

The adjustments are noncash adjustments and have no impact on the Company’s cash flows. On May 6, 2014, the Company completed its assessment of the impact of changes in reserve estimates for each of the years in the two year period ended December 31, 2013 and believes the effects of the restatements are as summarized in the following tables:

Reserve Quantity Information (amounts shown in whole numbers)

PROVED-DEVELOPED AND UNDEVELOPED RESERVES

	Previously Reported						Adjustment						As Restated
	Crude Oil (Bbl)			Natural Gas (Mcf)			Crude Oil (Bbl)			Natural Gas (Mcf)			Crude Oil (Bbl)			Natural Gas (Mcf)
December 31, 2011		6,757,860			28,620,040			(37,840	)		(17,945,420	)		6,720,020			10,674,620
Revisions of previous estimates		(351,407	)		(139,164	)		25,890			(314,990	)		(325,517	)		(454,154	)
Extensions and discoveries
Acquisitions of reserves		20,730			150,320			-			-			20,730			150,320
Production		(26,413	)		(134,736	)		-			-			(26,413	)		(134,736	)
December 31, 2012		6,400,770			28,496,460			(11,950	)		(18,260,410	)		6,388,820			10,236,050

Revisions of previous estimates		355,406			311,343			(109,870	)		61,000			245,536			372,343
Extensions and discoveries
Acquisitions of reserves		7,760			47,007			-			-			7,760			47,007
Production		(26,106	)		(152,470	)		-			-			(26,106	)		(152,470	)
December 31, 2013		6,737,830			28,702,340			(121,820	)		(18,199,410	)		6,616,010			10,502,930

PROVED DEVELOPED RESERVES
December 31, 2013		3,397,310			6,623,830			(83,910	)		(14,750	)		3,313,400			6,609,080
December 31, 2012		3,331,140			6,517,370			26,060			(194,120	)		3,357,200			6,323,250

F-30

TRANSCOASTAL CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(AMOUNTS SHOWN IN THOUSANDS)

Restatement of previously issued supplemental oil and natural gas disclosures (Unaudited) (continued)

Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2013

	Previously Reported			Adjustment			As Restated
Future cash inflows	$	811,564		$	(78,147	)	$	733,417
Less: Future production costs		(128,428	)		8,930			(119,498	)
Future development costs		(70,714	)		10,731			(59,983	)
Future income tax expense		(201,909	)		19,885			(182,024	)
Future net cash flows		410,513			(38,601	)		371,912
10% discount factor		(262,896	)		27,239			(235,657	)

Standardized measure of discounted future net cash inflows	$	147,617		$	(11,362	)	$	136,255

Estimated future development cost anticipated for following two years on existing properties	$	38,884		$	(10,732	)	$	28,152

Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2012

	Previously Reported			Adjustment			As Restated
Future cash inflows	$	757,700		$	(61,052	)	$	696,648
Less: Future production costs		(128,893	)		6,223			(122,670	)
Future development costs		(70,737	)		10,855			(59,882	)
Future income tax expense		(184,363	)		14,951			(169,412	)
Future net cash flows		373,707			(29,023	)		344,684
10% discount factor		(248,633	)		19,659			(228,974	)

Standardized measure of discounted future net cash inflows	$	125,074		$	(9,364	)	$	115,710

Estimated future development cost anticipated for following two years on existing properties	$	30,207		$	(8,655	)	$	21,552

F-31

TRANSCOASTAL CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(AMOUNTS SHOWN IN THOUSANDS)

Restatement of previously issued supplemental oil and natural gas disclosures (Unaudited) (continued)

Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2013

	Previously Reported			Adjustment			As Restated
Beginning of year	$	125,074		$	(9,364	)	$	115,710
Sales of crude oil and natural gas, net of production costs		(2,581	)		-			(2,581	)
Net changes in prices and production costs		9,657			(2,634	)		7,023
Development costs incurred during the period		716			-			716
Changes in future development costs		(250	)		(415	)		(665	)
Extensions, discoveries, and improved recoveries
Revisions of previous quantity estimates		10,553			(2,263	)		8,290
Accretion of discount		17,911			(859	)		17,052
Net change in income taxes		(11,356	)		1,540			(9,816	)
Purchases and sale of mineral interests		860			-			860
Timing and other		(2,966	)		2,632			(334	)

End of year	$	147,618		$	(11,363	)	$	136,255

Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2012

	Previously Reported			Adjustment			As Restated
Beginning of year	$	135,496		$	(11,047	)	$	124,449
Sales of crude oil and natural gas, net of production costs		(2,391	)		-			(2,391	)
Net changes in prices and production costs		(27,078	)		4,167			(22,911	)
Development costs incurred during the period		1,011			-			1,011
Changes in future development costs		(264	)		854			590
Extensions, discoveries, and improved recoveries
Revisions of previous quantity estimates		(7,721	)		(1,918	)		(9,639	)
Accretion of discount		20,535			(1,727	)		18,808
Net change in income taxes		4,819			(875	)		3,944
Purchases and sale of mineral interests		1,173			-			1,173
Timing and other		(509	)		1,185			676

End of year	$	125,071		$	(9,361	)	$	115.710

F-32

TRANSCOASTAL CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(AMOUNTS SHOWN IN THOUSANDS)

Supplemental oil and natural gas disclosures (Unaudited)

The following tables set forth supplementary disclosures for oil and natural gas producing activities in accordance with ASC 932 for the Company:

Capitalized Costs

The following table presents a summary of the Company’s oil and natural gas properties at December 31, 2013 and 2012:

	2013			2012
Oil and natural gas properties
Proved-developed producing properties	$	6,424		$	4,960
Proved-developed non producing properties		9,534			9,509
Proved-undeveloped properties		9,972			9,850
Less: Accumulated depletion		(2,330	)		(1,813	)

Total oil and natural gas properties, net of accumulated depletion	$	23,600		$	22,506

Costs Incurred

The following table summarizes costs incurred (capitalized and charged to expense) for oil and natural gas acquisition, exploration, development, and asset retirement costs for the years ended December 31, 2013 and 2012:

	2013		2012
Acquisitions of proved properties ⁽¹⁾	$	860	$	1,477
Exploration ⁽²⁾
Development ⁽³⁾		716		1,011
Asset retirement cost ⁽⁴⁾		37		1

Total costs incurred ⁽⁵⁾	$	1,613	$	2,489

⁽¹⁾ Property acquisition costs such as those incurred to purchase, lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place.

⁽²⁾ Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties.

⁽³⁾ Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing oil. This also includes prepaid drilling costs.

⁽⁴⁾ Asset retirement costs include costs to establish new asset retirement obligations.

⁽⁵⁾ Total costs incurred included oil properties, net of accumulated depletion and prepaid drilling costs of the accompanying consolidated balance sheets.

F-33

TRANSCOASTAL CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(AMOUNTS SHOWN IN THOUSANDS)

Supplemental oil and natural gas disclosures (Unaudited) (continued)

Oil Operating Results

Results of operations from oil and natural gas producing activities for the years ended December 31, 2012 and 2011, excluding the overhead and interest costs, were as follows:

	2013			2012

Crude oil and natural gas sales	$	3,728		$	3,682
Lease operating costs		(948	)		(1,114	)
Production taxes		(199	)		(177	)
Exploration costs
Depletion		(517	)		(498	)
Results of operations from oil and natural gas producing activities	$	2,064		$	1,893

Proved Reserves Methodology

The Company’s estimated proved reserves, as of December 31, 2012 and 2011, are made in accordance with the SEC’s final rule, Modernization of Oil and Gas Reporting, which amended Rule 4-10 of Regulation S-X (the “Final Rule”). As defined by the Final Rule, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods, and government regulations. Projects to extract the hydrocarbons must have commenced or an operator must be reasonably certain that it will commence the projects within a reasonable time. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the projects. Further requirements for assignment of estimated proved reserves include the following:

The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by natural gas, oil, and/or water 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. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons and highest known oil seen in well penetrations unless geoscience, engineering, or performance data and reliable technology establishes a lower or higher contact with reasonable certainty. Reliable technologies are any grouping of one or more technologies (including computational methods) that have been field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves which can be produced economically through applications of improved recovery techniques (including, but not limited to fluid injections) are included in the proved classification when 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, and other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based.

F-34

TRANSCOASTAL CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(AMOUNTS SHOWN IN THOUSANDS)

Supplemental oil and natural gas disclosures (Unaudited) (continued)

Proved Reserves Methodology (continued)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The prices used are the average crude oil and natural gas prices during the twelve 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.

Reserves engineering is a subjective process of estimating underground accumulations of crude oil, condensate, natural gas, and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserves estimate is a function of the quality of available date and of engineering and geological interpretation and judgment. The reserves actually recovered, the timing of production of those reserves, as well as operating costs and the amount and timing of development expenditures may be substantially different from original estimates. Revisions result primarily from new information obtained from development drilling, production history, field tests, and data analysis and from changes in economic factors including expectation and assumptions as to availability of financing for development projects.

Reserve Quantity Information (amounts shown in whole numbers)

The following table presents the Company’s estimate of its proved oil and natural gas reserves all of which are located in Texas. These estimates are inherently imprecise. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared with the assistance of an independent petroleum reservoir engineering firm. Oil reserves, which include condensate and natural gas liquids, are stated in barrels and gas reserves are stated in thousands of cubic feet.

PROVED-DEVELOPED AND UNDEVELOPED RESERVES

	Crude Oil (Bbl)			Natural Gas (Mcf)
December 31, 2011		6,720,020			10,674,620
Revisions of previous estimates		(325,517	)		(454,154	)
Extensions and discoveries
Acquisitions of reserves		20,730			150,320
Production		(26,413	)		(134,736	)
December 31, 2012		6,388,820			10,236,050
Revisions of previous estimates		245,536			372,343
Extensions and discoveries
Acquisitions of reserves		7,760			47,007
Production		(26,106	)		(152,470	)
December 31, 2013		6,616,010			10,502,930
PROVED DEVELOPED RESERVES
December 31, 2013		3,313,400			6,609,080
December 31, 2012		3,357,200			6,323,250

F-35

TRANSCOASTAL CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(AMOUNTS SHOWN IN THOUSANDS)

Supplemental oil and natural gas disclosures (Unaudited) (continued)

Reserve Quantity Information (amounts shown in whole numbers) (continued)

Future cash flows are computed by applying a first-day-of-the-month 12-month average price of natural gas (Henry Hub) and oil (West Texas Intermediate) to year end quantities of proved natural gas and oil reserves. Future operating expenses and development costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved natural gas and oil reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. For the year ended December 31, 2013, the oil and natural gas prices were applied at $96.94/Bbl and $3.67/MMBtu, $9.52/MMBtu after adjustments for liquids and BTU content, respectively, in the standardized measure. For the year ended December 31, 2012, the oil and natural gas prices were applied at $94.71/Bbl and $2,85/ MMBtu, $9.69/MMBtu after adjustments for liquids and BTU content, respectively, in the standardized measure.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil Reserves

The following table, which presents a standardized measure of discounted future cash flows and changes therein relating to proved oil reserves as of December 31, 2013 and 2012 and for the years then ended, is presented pursuant to ASC 932. In computing this data, assumptions other than those required by the Financial Accounting Standards Board could produce different results. Accordingly, the data should not be construed as being representative of the fair market value of the Partnership’s interests in proved oil reserves.

A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement costs or fair value of the Partnership’s interests in oil properties. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of time value of money and the risks inherent in reserve estimates of oil producing operations. There have been no estimates for future plugging and abandonment costs.

Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2013 and 2012

	2013			2012
Future cash inflows	$	733,417		$	696,647
Less: Future production costs		(119,498	)		(122,670	)
Future development costs		(59,983	)		(59,882	)
Future income tax expense		(182,024	)		(169,412	)
Future net cash flows		371,912			344,683
10% discount factor		(235,657	)		(228,973	)

Standardized measure of discounted future net cash inflows	$	136,255		$	115,710

Estimated future development cost anticipated for following two years on existing properties	$	28,152		$	21,552

F-36

TRANSCOASTAL CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(AMOUNTS SHOWN IN THOUSANDS)

Supplemental oil and natural gas disclosures (Unaudited) (continued)

Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2013 and 2012

	2013			2012
Beginning of year	$	115,710		$	124,449
Sales of crude oil, net of production costs		(2,581	)		(2,391	)
Net changes in prices and production costs		7,023			(22,911	)
Development costs incurred during the period		716			1,011
Changes in future development costs		(665	)		590
Extensions, discoveries, and improved recoveries
Revisions of previous quantity estimates		8,290			(9,639	)
Accretion of discount		17,052			18,808
Net change in income taxes		(9,816	)		3,944
Purchases and sale of mineral interests		860			1,173
Timing and other		(334	)		676

End of year	$	136,255		$	115,710

Significant Changes in Reserves for the Year Ended December 31, 2013 (amounts shown in whole numbers)

Net Changes in Prices and Production Costs : For the year ended December 31, 2013, the oil and natural gas prices were applied at $96.94/Bbl and $3.67/MMBtu, $9.52/MMBtu after adjustments for liquids and BTU content, respectively, in the standardized measure. At December 31, 2012, the oil and natural gas prices were applied at $94.71/Bbl and $2.85/ MMBtu, $9.69/MMBtu after adjustments for liquids and BTU content, respectively, in the standardized measure. Additionally, estimated future production costs per barrel of oil equivalent (BOE) decreased from December 31, 2012 to 2013.

Revisions of Previous Quantity Estimates: During the year ended December 31, 2013, the Company adjusted its previous estimates by 245,536 Bbl of crude oil and 372,343 Mcf of natural gas from primarily revisions of proved undeveloped reserves that the Company currently has interests in.

Accretion of Discount: Accretion during the year ended December 31, 2013 was the result of accretion of the future net revenues at a standard rate of 10% due to the passage of time.

Significant Changes in Reserves for the Year Ended December 31, 2012 (amounts shown in whole numbers)

Net Changes in Prices and Production Costs : For the year ended December 31, 2012, the oil and natural gas prices were applied at $94.71/Bbl and $2.85/MMBtu, $9.69/MMBtu after adjustments for liquids and BTU content, respectively, in the standardized measure. At December 31, 2011, the oil and natural gas prices were applied at $95.84/Bbl and $4.15/ MMBtu, $8.21/MMBtu after adjustments for liquids and BTU content, respectively, in the standardized measure. Additionally, estimated future production costs per barrel of oil equivalent (BOE) increased from December 31, 2011 to 2012.

F-37

TRANSCOASTAL CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(AMOUNTS SHOWN IN THOUSANDS)

Supplemental oil and natural gas disclosures (Unaudited) (continued)

Significant Changes in Reserves for the Year Ended December 31, 2012 (amounts shown in whole numbers) (continued)

Revisions of Previous Quantity Estimates: During the year ended December 31, 2012, the Company adjusted its previous estimates by (325,517) Bbl of crude oil and (454,154) Mcf of natural gas from primarily revisions of proved undeveloped reserves that the Company currently has interests in.

Accretion of Discount: Accretion during the year ended December 31, 2012 was the result of accretion of the future net revenues at a standard rate of 10% due to the passage of time.

F-38

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