Item Business
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General
Houston American Energy Corp is an independent oil and gas company focused on the development, exploration, exploitation, acquisition, and production of natural gas and crude oil properties. Our principal properties, and operations, are in the U.S. Permian Basin and the South American country of Colombia. Additionally, we have properties in the Louisiana U.S. Gulf Coast region.
We focus on early identification of, and opportunistic entrance into, existing and emerging resource plays. We do not operate properties but typically seek to partner with, or invest along-side, larger operators in the development of resources or retain interests, with or without contribution on our part, in prospects identified, packaged and promoted to larger operators. By entering these plays earlier, identifying stranded blocks and partnering with, investing along-side or promoting to, larger operators, we believe we can capture larger resource potential at lower cost and minimize our exposure to drilling risks and costs and ongoing operating costs.
We, along with our partners, actively manage our resources through opportunistic acquisitions and divestitures where reserves can be identified, developed, monetized and financial resources redeployed with the objective of growing reserves, production and shareholder value.
Properties
Our exploration and development projects are focused on existing property interests in the Texas Permian Basin, the South American country of Colombia and the onshore Louisiana Gulf Coast region.
Each of our property interests differ in scope and character and consists of one or more types of assets, such as 3-D seismic data, owned mineral interests, leasehold positions, lease options, working interests in leases, partnership or limited liability company interests, corporate equity interests or other mineral rights. Our percentage interest in each property represents the portion of the interest in the property we share with other partners in the property. Because each property consists of a bundle of assets that may or may not include a working interest in the project, our stated interest in a property simply represents our proportional ownership in the bundle of assets that constitute the property. Therefore, our interest in a property should not be confused with the working interest that we will own when a given well is drilled. Each of our exploration and development projects represents a negotiated transaction between the project partners relating to one or more properties. Our working interest may be higher or lower than our stated interest.
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The following table sets forth information relating to our principal properties as of December 31, 2024:
2024 Net Production
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Net Average Gross Net proved Oil Natural Gas Natural
acreage working producing reserves (bbls)(1) (mcf)(1) Gas Liquids (gallons)
interest % wells (boe)(1)
Texas 98 6.8 % 4 159,875 5,992 53,476 159,680
Louisiana 582 23.4 % - - - - -
Total U.S. 680 15.1 % 4 159,875 5,992 53,476 159,680
Colombia(2) 572 16 % 4 - - - -
Total 1,252 16 % 8 159,875 5,992 53,476 159,680
(1) All reserve and production information excludes wells operated
by Hupecol Meta in Colombia.
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(2) Net acreage and average working interest in Colombia are held
through our investment in Hupecol Meta, and are subject to pending approvals of (i) the proposed relinquishment of a portion of the acreage
within the Venus Exploration Area of the CPO-11 block; and (ii) the acquisition of the remaining 50% interest in the balance of the CPO-11
block previously farmed out to Parex Resources. See “Colombian Properties - CPO-11” below.
- United States Properties:
In the United States, our principal properties and operations are located in the on-shore Permian Basin and Gulf Coast region of Louisiana.
Texas Properties - Permian Basin
Reeves County. We hold a 18.1% average working interest in 320 gross acres in Reeves County, Texas, consisting of (1) the 160 gross acre Johnson Lease, in which we hold a 25% working interest, subject to a proportionate 5% back-in after payout, and (2) the 160 gross acre O’Brien Lease, in which we hold an average 11.2% working interest. Our Reeves County acreage lies within the Delaware sub-basin of the Permian Basin, with resource potential in the Wolfcamp, Bone Spring and Avalon formations. During 2017, we drilled and completed our initial wells on both lease blocks, the Johnson State #1H well and the O’Brien #3H well, both horizontally drilled and hydraulically fractured wells in the Wolfcamp A formation. The Johnson #1H well and O’Brien #3H well were both placed on gas lift during 2021 and were producing at December 31, 2024. For the year ended December 31, 2024, our production in Reeves County totaled 3,468 barrels of oil and 53,476 mcf of natural gas.
In June 2024, we participated in the drilling of six wells in the State Finkle Unit on the O’Brien Lease. All six wells are expected to commence production in March, 2025
As of December 31, 2024, no additional development or drilling operations are planned with respect to our Reeves County acreage.
Yoakum County. We hold a 15.9% average working interest, subject to a proportionate 10% back-in after payout, in an approximately 360 gross acre block in Yoakum County, Texas. Our Yoakum County acreage lies within the Midland sub-basin of the Permian Basin.
During 2019, we drilled the Frost #1H well, the first well on our Yoakum County acreage. The well was horizontally drilled, hydraulically fractured in the San Andres Formation and completed and commenced production in mid-2019. A second well on our Yoakum County acreage, the Frost #2H well, was horizontally drilled, hydraulically fractured in the San Andres Formation and completed and commenced production during the third quarter of 2020. For the year ended December 31, 2024, our production in Yoakum County totaled 2,524 barrels of oil.
As of December 31, 2024, no additional development or drilling operations are planned with respect to our Yoakum County acreage.
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Louisiana Properties
Our sole property in Louisiana consists of a 23.4% mineral interest in 2,485 gross acres in East Baton Rouge Parish.
There are no present wells, or plans to conduct drilling operations, on our Louisiana acreage.
- Colombian Properties:
At December 31, 2024, we held interests in a single block, through our equity investment in Hupecol Meta, LLC, operated by Hupecol Operating and affiliates, in Colombia covering 639,405 gross acres. We identify our Colombian prospect as the Venus Exploration Area within the CPO-11 block and remainder of the CPO-11 block.
The following table sets forth information relating to our interests in prospects in Colombia at December 31, 2024:
Property Operator Ownership Total Total Gross
Interest Gross Acres Gross Developed Acres Productive Wells
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CPO-11 - Venus Exploration Area Hupecol 16.0 % 3,573 1,332 4
Total 3,573 1,332 4
The CPO-11 concession, including the Venus Exploration Area, is located in the Llanos Basin and is owned and operated by Hupecol Meta.
CPO-11
During 2019, we acquired a two percent ownership interest in Hupecol Meta, LLC (“Hupecol Meta”). Hupecol Meta owns the 639,405 gross acre CPO-11 block in the Llanos Basin in Colombia. The CPO-11 block is comprised of the 69,128 acre Venus Exploration area and 570,277 acres which was 50% farmed out by Hupecol to Parex Resources. In 2021, Hupecol Meta increased its ownership interest in the CPO-11 block and we agreed to contribute $99,716. In 2022, we acquired additional interests in Hupecol Meta for an aggregate of $657,638. As a result of our acquisition of additional interests in 2021 and 2022, our ownership interest in Hupecol Meta was approximately 18% at December 31, 2024. Through our ownership interest in Hupecol Meta, at December 31, 2024, we hold an approximately 16% interest in the Venus Exploration Area and an approximately 8% interest in the remainder of the CPO-11 block.
The CPO-11 block covers almost 1,000 square miles. During 2023, in the Venus Exploration Area, Hupecol Meta drilled and completed the Venus 1-H horizontal well and the Venus 2-H ST1 well. At December 31, 2024, the Saturno ST1 and Venus 2A wells, both vertical wells, and the Venus 1-H and Venus 2-H ST1 wells, both horizontal wells, were on production in the Venus Exploration Area of the CPO-11 block.
Hupecol Meta has (i) proposed to relinquish approximately 62,139 gross acres within the Venus Exploration Area, decreasing its holding within that area to approximately 7,157 gross, and 1,145 net, acres; and (ii) agreed to acquire the 50% interest in the CPO-11 block farmed out to Parex Resources, which would increase Hupecol Meta’s net acreage position in the block to 91,244 acres. The relinquishment of such acreage and acquisition of the Parex interest are both subject to approval of the Colombian hydrocarbons agency, or ANH.
Our equity investment in Hupecol Meta is accounted for at cost and, accordingly, this report does not include any reserves, production and operating results of Hupecol Meta.
In late 2023, Hupecol advised that it intends to evaluate potential monetization of its assets in Colombia, including the interest in the CPO-11 block held by Hupecol Meta. Pending the outcome of Hupecol’s evaluation of, and potential efforts regarding, monetization of the CPO-11 block, we have no planned drilling operations, or other planned operations, in Colombia. There is no assurance as to the timing or outcome of Hupecol’s potential monetization of assets.
As of December 31, 2024, the Company determined it was necessary to take an impairment charge for our investment in Hupecol Meta due to indications that its earnings performance has deteriorated, and the investment is no longer viewed as viable. We determined that we are unlikely to receive any substantial amount of proceeds upon the sale of Hupecol Meta, rendering the value of the investment fully impaired.
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Drilling Activity
The following table summarizes the number of wells drilled through Hupecol Meta, during 2024, 2023 and 2022, excluding any wells drilled under farmout agreements, royalty interest ownership, or any other wells in which we do not have a working interest (direct or indirect).
Year Ended December 31,
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2024 2023 2022
Gross Net Gross Net Gross Net
Development wells, completed as:
Productive - - 2 0.32 - -
Non-productive - - - - - -
Total development wells - - 2 0.32 - -
Exploratory wells, completed as:
Productive - - - - 1 0.16
Non-productive 1 0.16 - - 1 0.16
Total exploratory wells - - 2 0.32
Productive wells are wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. During 2024, the operator of the O’Brien Lease, EOG, decided to drill six new wells on the Finkle State Unit. We decided to participate in the drilling of those wells. We anticipate production from those wells to begin in March, 2025. .
Hupecol Meta drilled a well in 2024 which turned out to be non-productive. Through our investment in Hupecol Meta, we own approximately 16% of the block on which the well was drilled.
Productive Wells
Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. As of December 31, 2024, we owned interests in 14 gross wells (including indirect interests in wells in Colombia through our equity interest in Hupecol Meta). As of December 31, 2024, we had interests in productive wells, categorized by geographic area, as follows:
Oil Wells Gas Wells
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United States
Gross 10 -
Net 0.7022 -
Colombia
Gross 4 -
Net 0.64 -
Total
Gross 14 -
Net 1.3422 -
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Volume, Prices and Production Costs
The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sales of gas and oil, categorized by geographic area (excluding our production, prices and costs attributable to wells operated by Hupecol Meta), for each of the three years ended December 31, 2024, 2023, and 2022:
Year Ended December 31,
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2024 2023 2022
Net Production:
Gas (Mcf):
United States 53,476 57,360 73,635
Colombia - - -
Total 53,476 57,360 73,635
Natural Gas Liquids (Gallons)
United States 159,680 179,506 248,506
Colombia - - -
Total 159,680 179,506 248,506
Oil (Bbls):
United States 5,992 7,971 10,688
Colombia - - -
Total 5,992 7,971 10,688
Average sales price:
Gas ($ per Mcf)
United States $0.17 $1.38 $5.13
Colombia - - -
Total $0.17 $1.38 $5.13
Natural Gas Liquids ($ per Gallon)
United States $0.71 $0.69 $1.07
Colombia - - -
Total $0.71 $0.69 $1.07
Oil ($ per Bbl)
United States 73.08 $74.08 $93.10
Colombia - - -
Total 73.08 $74.08 $93.10
Average production costs ($ per BOE):
United States 42.85 $27.03 $27.48
Colombia - - -
Total 42.85 $27.03 $27.48
Average production costs per BOE in 2024 increased to $42.85 per BOE from $27.03 in 2023 due to inflation-related increases in expenses and workover costs incurred in early 2024 related to two of our US wells.
Natural Gas and Oil Reserves
Reserve Estimates
The following tables set forth, by country and as of December 31, 2024, our estimated net proved oil and natural gas reserves, and the estimated present value (discounted at an annual rate of 10%) of estimated future net revenues before future income taxes (“PV-10”) and after future income taxes (“Standardized Measure”) of our proved reserves, each prepared in accordance with assumptions prescribed by the Securities and Exchange Commission (“SEC”). The below table excludes reserve and other information pertaining to assets operated by Hupecol Meta.
The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent. PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carry forwards and other factors. We believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
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These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.
Reserves (1)
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Oil Natural Gas NaturalGas Liquids Total (2)
(bbls) (mcf) (gal) (boe)
Reserve category
Proved Developed Producing
United States 29,380 339,210 959,650 108,764
Colombia(3) - - - -
Total Proved Developed Producing Reserves 29,380 339,210 959,650 108,764
Proved Non-Producing
United States 17,010 78,980 502,600 42,140
Colombia(3) - - - -
Total Proved Non-Producing Reserves 17,010 78,980 502,600 42,140
Total Proved Reserves 46,390 418,190 1,462,250 150,904
Proved Developed Proved Non-Producing Total Proved
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PV-10 (1) $537,870 $585,400 $1,123,270
Standardized measure (4) $537,870 $585,400 $1,123,270
(1) In accordance with
applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the PV-10 set forth
herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production
and future development costs, using prices and costs under existing economic conditions at December 31, 2024. For purposes of
determining prices, we used the unweighted arithmetical average of the prices on the first day of each month within the 12-month
period ended December 31, 2024. The average prices utilized for purposes of estimating our proved reserves were $71.96 per barrel of
oil, $0.52 per MMBTu of natural gas, and $0.71 per gallon of natural gas liquids for our US properties, adjusted by property for
energy content, quality, transportation fees and regional price differentials. The prices should not be interpreted as a prediction
of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative
expenses and debt service, future income taxes or to depreciation, depletion and amortization.
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(2) Natural gas is converted on the basis of six Mcf of gas per
one barrel of oil equivalent.
(3) As an equity investment accounted for at cost, we do not report
any reserves attributable to our investment in Hupecol Meta.
(4) The Standard Measure differs from PV-10 only in that the Standard
Measure reflects estimated future income taxes.
Due to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
Reserve Estimation Process, Controls and Technologies
The reserve estimates, including PV-10 and Standard Measure estimates, set forth above were prepared by Russell K. Hall & Associates, Inc. for our Permian Basin, Texas reserves.
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The reserves as of December 31, 2024 were determined in accordance with standard industry practices and SEC regulations by the licensed independent petroleum engineering firm. The calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry.
Our year-end reserve reports are prepared by reserve engineering firms based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geosciences and engineering data, and other information provided to them by our management team. Upon analysis and evaluation of data provided, the reserve engineering firms issue a preliminary appraisal report of our reserves. The preliminary appraisal report and changes in our reserves are reviewed by our President and board for reasonableness of the results obtained. Once any questions have been addressed, the reserve engineering firms issue final appraisal reports, reflecting their conclusions.
Russell K. Hall & Associates is an independent Midland, Texas based professional engineering firm providing reserve evaluation services to the oil and gas industry. Their report was prepared under the direction of Russell K. Hall, founder and President of Russell K. Hall & Associates. Mr. Hall holds a BS in Mechanical Engineering from the University of Oklahoma, is a registered professional engineer and a member of the Society of Petroleum Engineers, the Society of Independent Professional Earth Scientists and the West Texas Geological Society. Mr. Hall has more than 30 years of experience in reserve evaluation for the oil and gas industry and the oil and gas finance industry. Russell K. Hall & Associates, and its employees, have no interest in our company or our properties and were objective in determining our reserves.
The SEC’s rules with respect to technologies that a company can use to establish reserves allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a 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.
Our reserve engineering firm used a combination of production and pressure performance, simulation studies, offset analogies, seismic data and interpretation, geophysical logs and core data to calculate our reserves estimates.
Proved Undeveloped Reserves
We had no proved undeveloped reserves at either December 31, 2023 or December 31, 2024.
Developed and Non-Producing Acreage
The following table sets forth the gross and net developed and non-producing acreage (including both leases and concessions, but excluding acreage in which we hold a royalty interest but no working interest), categorized by geographical area, which we held as of December 31, 2024:
Developed Non-Producing
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Gross Net Gross Net
United States 3,040 98 2,485 582
Colombia 1,332 213 2,241 359
Total 4,372 311 4,726 941
Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well and acreage in which we hold a direct or indirect mineral interest with no potential development related lease expirations. Non-producing acreage is comprised of leased acres that are within an areas assigned to a well which is not yet producing, in which we hold a direct or indirect mineral interest.
As is customary in the oil and natural gas industry, we can generally retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from our developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced.
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Title to Properties
Title to properties is subject to royalty, overriding royalty, carried working, net profits, working and other similar interests and contractual arrangements customary in the gas and oil industry, liens for current taxes not yet due and other encumbrances. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than preliminary review of local records).
Investigation, including a title opinion of local counsel, generally is made before commencement of drilling operations.
Marketing
At December 31, 2024, we had no contractual agreements to sell our gas and oil production and all production was sold on spot markets.
Human Capital
As of December 31, 2024, we had 2 full-time employees and no part-time employees. The employees are not covered by a collective bargaining agreement, and we do not anticipate that any of our future employees will be covered by such agreements.
Competition
We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies, numerous independent oil and gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and gas business for a much longer time than our Company. These companies may be able to pay more for productive oil and gas properties, exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Regulatory Matters
Regulation of Oil and Gas Production, Sales and Transportation
The oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments. Compliance with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. Most jurisdictions in which we operate also have statutes, rules, regulations or guidelines governing the conservation of natural resources, including the unitization or pooling of oil and gas properties, minimum well spacing, plugging and abandonment of wells and the establishment of maximum rates of production from oil and gas wells. Some jurisdictions also require the filing of drilling and operating permits, bonds and reports. The failure to comply with these statutes, rules and regulations could result in the imposition of fines and penalties and the suspension or cessation of operations in affected areas.
Environmental Regulation
Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the discharge and disposition of generated waste materials and waste management, the reclamation and abandonment of wells, sites and facilities, financial assurance and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.
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The environmental laws and regulations applicable to our U.S. operations include, among others, the following United States federal laws and regulations:
● Clean Air Act, and its amendments, which govern air emissions;
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● Clean Water Act, which governs discharges into waters of the
United States;
● Comprehensive Environmental Response, Compensation and Liability
Act, which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”);
● Resource Conservation and Recovery Act, which governs the management
of solid waste;
● Oil Pollution Act of 1990, which imposes liabilities resulting
from discharges of oil into navigable waters of the United States;
● Emergency Planning and Community Right-to-Know Act, which requires
reporting of toxic chemical inventories;
● Safe Drinking Water Act, which governs the underground injection
and disposal of wastewater; and
● U.S. Department of Interior regulations, which impose liability
for pollution cleanup and damages.
Colombia has similar laws and regulations designed to protect the environment.
We routinely obtain permits for our facilities and operations in accordance with these applicable laws and regulations on an ongoing basis. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations.
The ultimate financial impact of these environmental laws and regulations is neither clearly known nor easily determined as new standards are enacted and new interpretations of existing standards are rendered. Environmental laws and regulations are expected to have an increasing impact on our operations. In addition, any non-compliance with such laws could subject us to material administrative, civil or criminal penalties, or other liabilities. Potential permitting costs are variable and directly associated with the type of facility and its geographic location. Costs, for example, may be incurred for air emission permits, spill contingency requirements, and discharge or injection permits. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.
Although we do not operate the properties in which we hold interests, noncompliance with applicable environmental laws and regulations by the operators of our oil and gas properties could expose us, and our properties, to potential costs and liabilities associated with such environmental laws. While we exercise no oversight with respect to any of our operators, we believe that each of our operators is committed to environmental protection and compliance. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.
Hydraulic Fracturing Regulation
Hydraulic fracturing, or “fracking”, is a common practice used to stimulate production of oil and natural gas from tight formations, including shales. Fracking involves the injection of fluids-usually consisting mostly of water but typically including small amounts of chemical additives-as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore.
Except as applies to federal lands, fracking generally is exempt from regulation under many federal environmental rules and is generally regulated at the state level.
For example, in Texas, the Texas Railroad Commission administers regulations related to oil and gas operations, including regulations pertaining to protection of water resources in connection with those operations. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.
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There is public controversy regarding fracking with regard to the use of fracking fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. Lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations restricting hydraulic fracturing are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply could have a material adverse effect on well operations and economics.
We do not operate wells but contract well operations to third party operators. Operators of our wells may perform fracking operations, or contract third parties to perform such operations, on wells in which we participate. Many newer wells would not be economical without the use of fracking to stimulate production from the well. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Climate Change Legislation and Greenhouse Gas Regulation
Federal, state and local laws and regulations are increasingly being enacted to address concerns about the effects the emission of “greenhouse gases” may have on the environment and climate. These effects are widely referred to as “climate change.” Since its December 2009 endangerment finding regarding the emission of greenhouse gases, the Environmental Protection Agency (the “EPA”) has begun regulating sources of greenhouse gas emissions under the federal Clean Air Act. Among several regulations requiring reporting or permitting for greenhouse gas sources, the EPA finalized its “tailoring rule” in May 2010 that determines which stationary sources of greenhouse gases are required to obtain permits to construct, modify or operate on account of, and to implement the best available control technology for, their greenhouse gases. The EPA’s final greenhouse gas reporting requirements pertain to certain oil and gas production facilities.
Moreover, the U.S. Congress has considered establishing a cap-and-trade program to reduce U.S. emissions of greenhouse gases. Under past proposals, the EPA would issue or sell a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of such legislation, if ever adopted, would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products, and natural gas. In addition, while the prospect for such cap-and-trade legislation by the U.S. Congress remains uncertain, several states have adopted, or are in the process of adopting, similar cap-and-trade programs.
As a crude oil and natural gas company, the debate on climate change is relevant to our operations because the regulatory response is designed to reduce demand for, and use of, our products, oil and gas, in favor of alternative forms of energy. We cannot presently predict the ultimate impact of existing or future climate change initiatives on our company or our industry although we do anticipate that, at a minimum, we will incur additional operating and other costs to respond to such initiatives.
Web Site Access to Reports
Our Web site address is www.houstonamerican.com. We make available, free of charge on our Web site, our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the United States Securities and Exchange Commission. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.
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