Item 1. Description of Business
GENERAL
Spindletop Oil & Gas Co. is an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas; the rental of oilfield equipment; and through one of its subsidiaries, the gathering and marketing of natural gas. The terms the "Company", "We", "Us" or “Spindletop” are used interchangeably herein to refer to Spindletop Oil & Gas Co. (“SOG”) and its wholly owned subsidiaries, Spindletop Drilling Company ("SDC"), and Prairie Pipeline Co. (“PPC”).
The Company has focused its oil and gas operations principally in Texas, although we operate properties in six states including: Texas, Oklahoma, New Mexico, Louisiana, Alabama and Arkansas. We operate a majority of our projects through the drilling and production phases. Our staff has a great deal of experience in the operations arena. We have traditionally leveraged the risks associated with drilling by obtaining industry partners to share in the costs.
In addition, the Company, through PPC, owns approximately 26.1 miles of pipelines located in Texas, which are used for the gathering of natural gas. These gathering lines are located in the Fort Worth Basin and are being utilized to transport the Company's natural gas as well as natural gas produced by third parties.
Website Access to Our Reports
We make available free of charge through our website, www.spindletopoil.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission. Information on our website is not a part of this report.
Operating Approach
We believe that a major attribute of the Company is its long history with, and extensive knowledge of, the Fort Worth Basin of Texas. Our technical staff has an average of over 21 years oil and gas experience, most of it in the Fort Worth Basin.
One of our strengths has been the ability of the Company to look at cost effective ways to grow our production. We have traditionally increased our reserve base in one of two ways. Initially, in the 1970s and 1980s, the Company obtained its production through an exploration and development drilling program focused principally in the Fort Worth Basin of North Texas. Today, the Company has retained many of these wells as producing properties and holds a large amount of acreage by production in that Basin.
From the 1990s through 2003, the Company took advantage of the lower product prices by cost effectively adding to its reserve base through value-priced acquisitions. We found that through selective purchases we could make producing property acquisitions that were more cost effective than drilling.
During this time period, the Company acquired a large number of operated and non-operated oil and gas properties in various states.
From 2003 through the fourth quarter of 2008, we returned our focus to a strategy of development drilling with an emphasis on our Barnett Shale acreage. Since 2009, we split our focus by looking for value-priced acquisitions combined with the development drilling prospects. Currently we are continuing our efforts to acquire producing properties and develop our leasehold acreage. We are looking at growth through acquisitions of producing properties as well as through the drilling of new wells. With current oil and natural gas prices and high costs to produce, we believe that it is prudent to carefully evaluate all our options and make sure that each transaction can be supported in today’s price environment.
Strategic Business Plans
One of our key strategies is to attempt to maintain shareholder value through implementation of plans for selective drilling and value priced acquisitions to the extent the economics of such projects work in this low energy price environment and development of assets to the extent feasible. The Company's long-term focus is to grow its oil and natural gas production through a strategic combination of selected property acquisitions, to the extent feasible, and an exploration and development program primarily based on developing its leasehold acreage. Additionally, the Company plans to continue to rework existing wells to increase production and reserves.
The Company's primary area of operation has been in the State of Texas with an emphasis in the geological province known as the Fort Worth Basin. We plan to continue to focus on operations in Texas, and we want to capitalize on our strengths which include an extensive knowledge of the various reservoirs in Texas, experience in operations in this geographic area, development of lease holdings, and utilization of existing infrastructure to minimize costs.
The Company will continue to generate and evaluate prospects using its own technical staff. The Company intends to fund operations primarily from cash flow generated by its operations.
Project Significant Areas
The Company owns various interests in wells located in 15 states and the Company’s operations are currently located in 6 of those states which include Alabama, Arkansas, Louisiana, Oklahoma, New Mexico and Texas.
The Company holds approximately 94,046 gross acres under lease in 15 states. The majority of the leases are held by production. A breakout of the Company’s leasehold acreage by geographic area is as follows:
The majority of the Company’s net acres (68.6%) are located in Texas.
A breakout of the Company's most significant oil and gas reserves by geographic area is as follows:
North Texas - Fort Worth Basin & Bend Arch
The Fort Worth Basin-Bend Arch Province has been a focal point of the Company since its inception. Our technical personnel have an average of 21 years of exploration, drilling, completing, and production experience extracting natural gas and oil from both conventional and unconventional hydrocarbon deposits found across the basin. Furthermore, the Company maintains comprehensive and extensive dossiers of geologic and engineering data gathered from the province. Exploration and development drilling for hydrocarbons across the Fort Worth Basin-Bend Arch Province continue to remain strong.
The Fort Worth Basin-Bend Arch Province is a major United States onshore natural gas-prone expanse containing multiple pay zones that range in depth from one thousand to nine thousand (1,000-9,000) feet. Improved technical advances in fracturing and stimulation technologies have helped unlock natural gas and oil reserves from the hydrocarbon bearing Barnett Shale Formation; and thus, continue to bolster vigorous exploration and development activities that target these conventional and unconventional reservoir reserves throughout the province.
The Barnett Shale is a thick natural gas and oil bearing stratigraphic zone found throughout the Fort Worth Basin-Bend Arch Province. The natural gas reserves in place are significant; however, as a consequence of the extreme low permeability character of the shales, it has been technically challenging to produce these reserves. According to the United States Geological Survey assessment, an estimated 26.7 trillion cubic feet (TCF) of undiscovered natural gas, 98.5 MMBO of undiscovered oil, as well as a mean of 1.1 BBNGL of undiscovered natural gas liquids reserves remain within the 54,000 square mile Fort Worth Basin-Bend Arch Province. More than 98 percent or approximately 26.2 TCF of the undiscovered natural gas is contained in the organic-rich Mississippian Barnett Shale. Combined, recent advances in hydraulic fracturing, completion procedures, and improvements in pump technology, as well as refined horizontal well drilling technologies, continue to enable the economic recovery of natural gas and oil reserves from tight low-permeability reservoirs found throughout the Fort Worth Basin-Bend Arch Province. Undiscovered conventional reservoir natural gas reserves are estimated to be 467 billion cubic feet of gas (BCFG), the majority of which is dissolved in conventional oil accumulations (source: United States Geological Survey Energy Resource Program).
The Company has 9,754 gross acres under lease across the prolific Fort Worth Basin-Bend Arch Province, the majority of which is held by production from the more shallow producing zones. The Company uses recent and emerging technologies, as well as proven industry practices, to develop and produce oil and natural gas from its properties. Additionally, the Company has a dedicated and well-trained team of employees and professional staff that continually seek out low-risk profitable drilling and acquisition opportunities throughout the Fort Worth Basin-Bend Arch Province.
West Texas
During the fourth quarter of 2013, the Company spudded the Baldwin #1C well in the Humphrey-Chapman Field in Haskell County, Texas. The well reached a total depth of 4,276 ft. in the Strawn formation. Production casing was set to total depth on November 3, 2013. Subsequent to the end of the year, on January 29, 2014, the well was perforated in the Strawn Sand from 4,245 ft. to 4,247 ft. and the perforations were broken down with lease oil. The well swab tested a small volume oil and was plugged back on April 1, 2014 and the Strawn Lime was perforated from 4,072 ft. to 4,078 ft. and acidized with 750 gallons of 15% NEFE acid then fractured. After swab testing, it was determined that the well was uneconomical. Subsequent to the year end, the well was plugged and abandoned on January 20, 2015. The Company owns a 45% operated working interest and a 33.75% net revenue interest in the well.
Effective April 1, 2014, the Company acquired an additional 25.0% working interest with a 17.5% net revenue interest in its Petit Pois lease located in Glasscock County, Texas. This additional acquisition brought the Company’s interest in its Petit Pois #1 well and associated leasehold to a total 51.5% working interest with a 36.05% net revenue interest.
Effective April 1, 2014, the Company acquired an additional 10.0% working interest with an 8.0% net revenue interest in its Opal lease located in Martin County, Texas. This additional acquisition brought the Company’s interest in the Opal #1 well and associated leasehold to a total 55.858330% working interest with a 44.686667% net revenue interest.
Effective June 30, 2014, the Company acquired operations and a 100% working interest with a 75% net revenue interest in the Jones #1 well and associated 326.74 acre leasehold located in Gaines County, Texas. The well produces approximately 6 BOPD and 260 BWPD from perforations at a depth of 11,050 ft. to 11,084 ft. in the Block A-7 (Devonian) Field.
During the fourth quarter of 2014, the Company participated for a 2.62033% non-operated working interest with a 2.12903% net revenue interest in the drilling of the Moore Hooper #1H well located in Phantom (Wolfcamp) field of Loving County, Texas. The well is a horizontal well targeting the Wolfcamp “B” at a depth of 11,096 ft. TVD with a projected total measured depth of 15,400 ft. The well was spud on November 6, 2014 and surface casing was set and cemented at 4,260 ft. on November 11, 2014. The Operator utilized a spudder rig to drill and set surface casing and then moved in a larger rig to drill the curve and lateral. The larger rig was in the process of rigging up on December 31, 2014.
During the fourth quarter of 2014, the Company participated for a 2.62033% non-operated working interest with a 2.12903% net revenue interest in the drilling of the Moore Hooper #2H well located in the Phantom (Wolfcamp) field of Loving County, Texas. The well is a horizontal well targeting the Wolfcamp “A” at a depth of 10,908 ft. TVD with a projected total measured depth of 16,000 ft. The well was spud on November 26, 2014, and surface casing was set and cemented at a depth of 4,183 ft. The vertical and the curve portion of the well were then drilled and intermediate casing was set and cemented through the curve at a depth of 10,197 ft. on December 13, 2014. The Operator utilized a spudder rig to drill and set the surface casing and intermediate casing strings. The Operator plans to move in a larger rig to drill the remaining portion of the curve and the lateral. The larger rig had not arrived on location as of December 31, 2014.
In the fourth quarter of 2014 the Company, as Operator, drilled the Miller #2 well located in the Noodle, NW (Canyon Sand) field of Jones County, Texas. The well is a vertical well targeting the Canyon Sands. The well was spud on October 11, 2014 and reached a TD of 4,360 ft. on October 21, 2014. Production casing was set and the well was awaiting completion at year end. The Company owns a 76% working interest in this well.
Texas Panhandle
During the third quarter of 2014 the Company, as Operator, participated for a 29.1606% working interest with a 21.87045% net revenue interest in the drilling of the Pope #140-4H well in the Pan Petro Field in Ochiltree County, Texas. The horizontal well was spud on July 8, 2014 and reached a total measured depth of 8,874 ft. on August 15, 2014 in the Cleveland Sand Formation. The TVD was 6,486 ft. and the lateral length was approximately 1,943 ft. The well was awaiting completion as of December 31, 2014.
East Texas
Effective January 1, 2014, the Company acquired an additional 0.208680% working interest with a 0.169929% net revenue interest in its Watts Gas Unit #1 located in Marion County, Texas. This additional acquisition brought the Company’s interest in the well to a total 51.84462% working interest with a 41.826729% net revenue interest. The Company also acquired non-operated working interests in two nearby oil wells. The Company acquired a 1.5625% working interest and a 1.22784% net revenue interest in the C.M. Watts #1 well, and a 1.400720% working interest with a 1.129830% net revenue interest in the Wendell Brevard #1 well.
During the third quarter of 2014, the Company participated for a 6.3458162% non-operated working interest with a 4.75936215% net revenue interest in the drilling of the Patrick #2H well located in the Halliday (Woodbine) Field of Leon County, Texas. The well was spud on August 25, 2014 and reached a total measured depth of 14,522 ft. on September 26, 2014. The well is a horizontal well targeting the Woodbine Sands at a depth of 7,539 ft. TVD, has a 6,603 ft. long lateral and was completed in October 2014 using the perf. and plug method. The lateral was perforated from 7,920 ft. to14,357 ft. and was hydraulically fractured with 6,610,620 pounds of sand and 75,768 bbls of gelled water in 26 stages. First day of production was reported as November 15, 2014. The well had a reported initial potential of 153 bopd, 355 mcfgpd and 435 bwpd on December 30, 2014.
Also, during the third quarter of 2014, the Company participated for a 1.30148796% non-operated working interest with a 1.261019% net revenue interest in the drilling of the Carr-Ward #2H well located in the Halliday (Woodbine) Field of Leon County, Texas. The well was spud on October 7, 2014, reached a total measured depth of 15,521 ft. on November 16, 2014 and casing was run in the lateral and tied back to the intermediate casing on November 21, 2014. The well is a horizontal well targeting the Woodbine Sands at a depth of 7,267 ft. TVD. Completion operations on this well were ongoing as of December 31, 2014.
South Texas
During the first quarter of 2014, the Company spudded the James Agnes Hynes #31 well on February 20, 2014 in the Papalote E. Field in Bee County, Texas. The well reached a total depth of 3,267 ft. in the Catahoula formation. The well was cased to TD and the Catahoula String sand was perforated from 3,241 ft. to 3,242.5 ft. The perforations were broken down with lease oil and the well was placed on pump producing at a rate of 32 bopd and 43 bswpd. The Company owns a 100% working interest with a 60.83984% net revenue interest in this well.
North Texas
During the fourth quarter of 2014, the Company acquired an additional 2.285714% working interest and a 1.714286% net revenue interest in its Lebleu #1 well located in the Sipes Springs (Marble Falls) field in Comanche County, Texas. This additional acquisition brought the Company’s interest in the well to a total 69.277146% working interest with a 51.957861% net revenue interest.
During the third quarter of 2014, the Company plugged and abandoned its Liles #1 well in Parker County, Texas. The well had been shut-in for numerous years as uneconomical and there were no remaining zones to exploit.
New Mexico
Effective May 1, 2014, the Company acquired an additional 1.041667% working interest with a 0.859375% net revenue interest in each of its Ross Federal #1, #2, and #3 wells located in Chavez County, New Mexico. This additional acquisition brought the Company’s interest in each of these wells to a total 85.416668% working interest with a 70.468749% net revenue interest.
Effective May 1, 2014, the Company acquired an additional 1.082494% working interest with a 0.936357% net revenue interest in its Jack Federal #1 well located in Chavez County, New Mexico. This additional acquisition brought the Company’s interest this well to a total 85.083052% working interest with a 73.596839% net revenue interest.
During the third quarter of 2014, the Company participated for a 6.25% non-operated working interest with a 4.6875% net revenue interest in the drilling of the State Line #1 well located in the Sawyer Field of Lea County, New Mexico. The well was drilled to a depth to a depth of 5,438 ft. in the San Andres Formation. Production casing was set and cemented in the wellbore. The San Andres was perforated from 4,934 ft. to 4,998 ft. and acidized with 5,000 gals of 15% acid. The well was placed on pump on September 25, 2014. The average production of the first 30 days was 4 bopd and 4 bswpd. The well was shut down and waiting on electrification as of December 31, 2014.
Oklahoma
During the third quarter of 2014, the Company participated for a 1.53625% non-operated working interest with a 1.1425744% net revenue interest in the drilling of the Siebold #1-2H well located in the Verden (Hoxbar) Field of Grady County, Oklahoma. The well was spud on September 8, 2014 and reached a total measured depth of 16,149 ft. in the Hoxbar Sandstone on November 10, 2014. A production liner was set inside the lateral wellbore on November 12, 2014. The well had a TVD of 11,036 ft., and was completed using the perf. and plug method. The well was fractured with a total of 4,500,000 pounds of sand and 114,000 barrels of linear gel in 21 stages. The plugs were drilled out on December 19, 2014, and first production occurred on December 22, 2014. The peak production was reported on December 27, 2014 at a rate of 1,278 bopd, 1,407 mcfgpd and 989 bwpd. As of December 31, 2014, the well was flowing at a rate of 1,184 bopd, 1,329 mcfgpd and 539 bswpd.
Louisiana
During the third quarter of 2014, the Company acquired an additional 16.3% working interest with a net revenue interest of 12.175748% in its Mayers #1 well, and an additional 16.3% working interest its Savoy #1 well in Livingston Parish, Louisiana. This additional acquisition brought the company’s interest to a total working interest of 55.316667% and a 41.320356% net revenue interest.
Alabama
During the first quarter of 2014, the Company participated for an 8.16392% non-operated working interest with a 5.8359% net revenue interest in the drilling of the Jones 28-7, 4-13 well located in the Brooklyn Field of Conecuh County, Alabama. The well was drilled to a depth of 11,775 ft. and cased. The well was perforated in the Upper Smackover formation at a depth of 11,449 ft. to 11,461 ft. The well was acidized with 3,000 gallons of 15% NEFE acid on March 5, 2014. The well swab tested and recovered 33 BO and 3 BW in a 12 hour period. Due to low fluid entry, the well was given a fracture treatment of 128,016 pounds of bauxite on June 11, 2014. The well was then swab tested and placed on pump. The well was producing 8 bopd and 10 bswpd as of October 28, 2014.
For all of the above wells, the Company cautions that the initial production rates of a newly completed well or newly recompleted well or the production rates at the effective date of acquisition may not be an indicator of stabilized production rates or an indicator of the ultimate recoveries obtained.
Oil and Natural Gas Reserves
The Company’s net proved oil and natural gas reserves have been estimated by Company personnel. (See footnote 18 to the financial statements). No separate independent reserve report analysis has been prepared by an independent third party.
The net proved crude oil and natural gas reserves of the Company as of December 31, 2014 were 404,506 barrels of oil and condensate and 6.839 BCF of natural gas. Based on SEC guidelines, the reserves were classified as follows:
Only reserves that fell within the Proved classification were considered. Other categories such as Probable or Possible Reserves were not considered. No value was given to the potential future development of behind pipe reserves, untested fault blocks, or the potential for deeper reservoirs underlying the Company's properties. Shut-in uneconomic wells and insignificant non-operated interests were excluded.
On a BOE (barrel of oil equivalent) basis (6 MCF/BOE), the net reserves are:
The Company has operational control over the majority of these reserves and can therefore to a large extent control the timing of development and production.
Financial Information Relating to Industry Segments
The Company has three identifiable business segments: (1) exploration, acquisition, development and production of oil and natural gas, (2) natural gas gathering, and (3) commercial real estate investment. Footnote 15 to the Consolidated Financial Statements filed herein sets forth the relevant information regarding revenues, income from operations, and identifiable assets for these segments.
Narrative Description of Business
The Company is engaged in the exploration, development, acquisition and production of oil and natural gas, and the gathering and marketing of natural gas. The Company is also engaged in commercial real estate leasing through leasing office space to non-related third party tenants in the Company’s corporate headquarters office building.
Principal Products, Distribution and Availability
The principal products marketed by the Company are crude oil and natural gas which are sold to major oil and gas companies, brokers, pipelines and distributors, and oil and natural gas properties which are acquired and sold to oil and natural gas development entities. Reserves of oil and natural gas are depleted upon extraction, and the Company is in competition with other entities for the discovery of new prospects.
The Company is also engaged in the gathering and marketing of natural gas through its subsidiary PPC, which owns 26.1 miles of pipelines, and currently gathers approximately 1,063 mcfgpd. Natural gas is gathered for a fee. Substantially all of the natural gas gathered by the Company is produced from wells that the Company operates and in which it owns a working interest.
The Company owns land and a two story commercial office building in Dallas, Texas, which it uses as its principal headquarters office. The Company leases the remainder of the building to non-related third party commercial tenants at prevailing market rates.
Patents, Licenses and Franchises
Oil and natural gas leases of the Company are obtained from the owner of the mineral estate. The leases are generally for a primary term of three or more years, and often have extension options for an equivalent period as the original primary term for payment of additional bonus consideration. The leases customarily provide for extension beyond their primary term for as long as oil and natural gas are produced in commercial quantities or other operations are conducted on such leases as provided by the terms of the leases.
The Company currently holds interests in producing and non-producing oil and natural gas leases. The existence of the oil and natural gas leases and the terms of the oil and natural gas leases are important to the business of the Company because future additions to reserves will come from oil and natural gas leases currently owned by the Company, and others that may be acquired, when they are proven to be productive. The Company is continuing to purchase oil and natural gas leases in areas where it currently has production, and also in other areas.
Dependence on Customers
The following is a summary of significant purchasers / operators (listed by percent of total oil and natural gas sales) from oil and natural gas produced by the Company for the three-year period ended December 31, 2014.
Oil and natural gas is sold to approximately 123 different purchasers under market sensitive, short-term contracts computed on a month to month basis.
Except as set forth above, there are no other customers of the Company that individually accounted for more than two percent of the Company's oil and natural gas revenues during the three years ended
December 31, 2014.
The Company currently has no hedged contracts.
Prospective Drilling Activities
The Company's primary oil and natural gas prospect generation and acquisition efforts have been in known producing areas in the United States with emphasis devoted to Texas.
The Company intends to use a portion of its available funds to participate in drilling activities. The Company does not own any drilling rigs and all drilling activity is performed by independent drilling contractors. The Company does not refine or otherwise process its oil and natural gas production.
Exploration for oil and natural gas is normally conducted with the Company acquiring undeveloped oil and natural gas leases under prospects, and carrying out exploratory drilling on the prospective leasehold with the Company retaining a majority interest in the prospect. Interests in the property are sometimes sold to key employees and associated companies at cost. Also, interests may be sold to third parties with the Company retaining an overriding royalty interest, carried working interest, or a reversionary interest.
A prospect is a geographical area designated by the Company for the purpose of searching for oil and natural gas reserves and reasonably expected by it to contain at least one oil or natural gas reservoir. The Company utilizes its own funds along with the issuance of common stock and options to purchase common stock in some limited cases, to acquire oil and gas leases covering the lands comprising the prospects. These leases are selected by the Company and are obtained directly from the landowners, as well as from land men, geologists, other oil companies, some of whom may be affiliated with the Company, and by direct purchase, farm-in, or option agreements. After an initial test well is drilled on a property, any subsequent development drilling of such prospect will normally require the Company to fund the development activities.
Special Tax Provisions
See Footnote 8 to Consolidated Financial Statements regarding the accounting for income taxes.
Employees
The Company employs or contracts for the services of a total of approximately seventy people. Thirty-five are full-time employees. The remainder are part-time employees or independent contractors. We believe that our relationships with our employees are good.
In order to effectively utilize our resources, we employ the services of independent consultants and contractors to perform a variety of professional and technical services, including in the areas of lease acquisition, land related documentation and contracts, drilling and completion work, pumping, inspection, testing, maintenance and specialized services. We believe that it can be more cost effective to utilize the services of consultants and independent contractors for some of these services.
We depend to a large extent on the services of certain key management personnel and officers, and the loss of any these individuals could have a material adverse effect on our operations. The Company does not maintain key-man life insurance policies on its employees.
Financial information about foreign and domestic operations and export sales
All of the Company's business is conducted domestically, with no export sales.
Compliance with Environmental Regulations
Our oil and natural gas operations are subject to numerous United States federal, state, and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes, and clean-up of contaminated sites. We could incur material costs, including clean-up costs, fines, civil and criminal sanctions, and third party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken. In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent.
Glossary of Oil and Gas Terms
The following are abbreviations and definitions of terms commonly used in the oil and gas industry that are used in this Report. The terms defined herein may be found in this report in both upper and lower case or a combination of both.
"BBL" means a barrel of 42 U.S. gallons.
“BBNGL” means billion barrels of natural gas liquids.
“BCF” or “BCFG” means billion cubic feet.
"BOE" means barrels of oil equivalent; converting volumes of natural gas to oil equivalent volumes using a ratio of six Mcf of natural gas to one Bbl of oil.
“BOPD” means barrels of oil per day.
"BTU" means British Thermal Units. British Thermal Unit means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
“BSWPD” means barrels of salt water per day.
"Completion" means the installation of permanent equipment for the production of oil or natural gas.
"Development Well" means a well drilled within the proved area of an oil or natural gas reservoir to the depth of a strata graphic horizon known to be productive.
"Dry Hole" or "Dry Well" means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
"Exploratory Well" means a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new production reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
"Farm-Out" means an agreement pursuant to which 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 or reversionary interest in the lease. The interest received by an assignee is a "farm-in" and the assignor issues a "farm-out."
"Farm-In" see "Farm-Out" above.
"Gas" means natural gas.
"Gross" when used with respect to acres or wells, refers to the total acres or wells in which we have a working interest.
"Infill Drilling" means drilling of an additional well or wells provided for by an existing spacing order to more adequately drain a reservoir.
"MCF" or “MCFG” means thousand cubic feet.
“MCFGPD” means thousand cubic feet of natural gas per day.
"MCFE" means MCF of natural gas equivalent; converting volumes of oil to natural gas equivalent volumes using a ratio of one BBL of oil to six MCF of natural gas.
“MD” means measured depth.
“MMBO” means million barrels of oil.
"MMBTU" means one million BTUs.
"Net" when used with respect to acres or wells, refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company.
"Net Production" means production that is owned by the Company less royalties and production due others.
"Non-Operated" or "Outside Operated" means wells that are operated by a third party.
“Oil and Gas” means oil and natural gas.
"Operator" means the individual or company responsible for the exploration, development, production and management of an oil or gas well or lease.
“Overriding Royalty” means a royalty interest which is usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
"Present Value" ("PV") when used with respect to oil and natural gas reserves, means the estimated future gross revenues to be generated from the production of proved reserves calculated in accordance with the guidelines of the SEC, net of estimated production and future development costs as of the date of estimation without future escalation, and discounted using an annual discount rate of 10%. Prices are not escalated and are computed using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of the year (except to the extent a contract specifically provides otherwise). No effect is given to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization.
"Productive Wells" or "Producing Wells" consist of producing wells and wells capable of production, including wells waiting on pipeline connections.
"Proved Developed Reserves" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
"Proved Reserves" means the estimated quantities of crude oil and natural gas which upon analysis of geological and engineering data appear with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if either actual production or conclusive formation
tests support economic producibility. The area of a reservoir considered proved
includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which
can be reasonably judged as economically productive on the basis of available geological
and engineering data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery
techniques (such as fluid injection) are included in the "proved" classification when successful
testing by a pilot project, or the operation of an installed program in the reservoir, provides
support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil that may become
available from known reservoirs but is classified separately as "indicated additional reserves";
(B) crude oil and natural gas, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics or economic factors; (C) crude oil and
natural gas that may occur in undrilled prospects; and (D) crude oil and natural gas that may
be recovered from oil shales, coal, gilsonite and other such resources.
"Proved Undeveloped Reserves" means reserves that are recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
"Recompletion" means the completion for production of an existing well bore in another formation from that in which the well has been previously completed.
"Reserves" means proved reserves.
"Reservoir" means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
"Royalty" means an interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
“TCF” means trillion cubic feet.
“TD” means total depth.
“TVD” means true verticle depth,
"2-D Seismic" means an advanced technology method by which a cross-section of the earth's subsurface is created through the interpretation of reflecting seismic data collected along a single source profile.
"3-D Seismic" means an advanced technology method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.
"Working Interest" means an interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties.
"Workover" means operations on a producing well to restore or increase production.
Item 1A.
Item 1A. Risk Factors
Risks related directly to our Company
One should carefully consider the following risk factors, in addition to the other information set forth in this Report, before investing in shares of our common stock. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock. Some information in this Report may contain "forward-looking" statements that discuss future expectations of our financial condition and results of operation. The risk factors noted in this section and other factors could cause our actual results to differ materially from those contained in any forward-looking statements.
Uncertainties regarding the global economic and financial environment could lead to an extended national or global economic recession. A slowdown in economic activity caused by a recession would likely reduce national and worldwide demand for oil and natural gas and result in lower commodity prices for long periods of time. Costs of exploration, development and production have not yet adjusted to current economic conditions, or in proportion to the significant reduction in product prices.
During the second quarter of 2014, oil and gas prices started to decline worldwide. The Company has experienced a similar decline in the selling prices of it products. Average quarterly crude oil prices per bbl for the year ended December 31, 2014 were $113.76, $100.55, $98.05, and $83.03 respectively. Average quarterly natural gas prices per Mcf were $4.64, $4.71, $4.45, and $4.06 respectively. During the first quarter of 2015, crude oil prices for West Texas Intermediate have fallen into the low $40-$45 dollar range, and could possibly go even lower. Natural gas prices for the same period have decreased to under $3.00 per Mcf. The decreases in the Company’s product prices have a direct effect on its cash flow and profits. Prolonged, substantial decreases in oil and natural gas prices would likely have a material adverse effect on the Company’s business, financial condition, and results of operations, and could further limit the Company's access to liquidity and credit, and could hinder its ability to satisfy its capital requirements.
In the past several years, capital and credit markets have experienced volatility and disruption. Given the levels of market volatility and disruption, the availability of funds from those markets may diminish substantially. Further, arising from concerns about the stability of financial markets generally and the solvency of borrowers specifically, the cost of accessing the credit markets has increased as many lenders have raised interest rates, enacted tighter lending standards, or altogether ceased to provide funding to borrowers.
Due to these potential capital and credit market conditions, the Company cannot be certain that funding will be available in amounts or on terms acceptable to the Company. The Company is evaluating whether current cash balances and cash flow from operations alone would be sufficient to provide working capital to fully fund the Company's operations. Accordingly, the Company is evaluating alternatives, such as joint ventures with third parties, or sales of interest in one or more of its properties. Such transactions, if undertaken, could result in a reduction in the Company's operating interests or require the Company to relinquish the right to operate the property. There can be no assurance that any such transactions can be completed or that such transactions will satisfy the Company's operating capital requirements. If the Company is not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to the Company, the Company would be required to curtail its expenditures or restructure its operations, and the Company would be unable to continue its exploration, drilling, and recompletion program, any of which would have a material adverse effect on its business, financial condition, and results of operations.
We face significant competition, and many of our competitors have resources in excess of our available resources.
The oil and natural gas industry is highly competitive. We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and sale of crude oil and natural gas. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than us. Such companies may be able to pay more for productive oil and gas properties and 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 depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts.
Drilling activities are subject to many risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental requirements, and shortages in or delays in the delivery of equipment and services. In today's environment, shortages make drilling rigs, labor and services difficult to obtain and could cause delays or inability to proceed with our drilling and development plans. Such equipment shortages and delays sometimes involve drilling rigs where inclement weather prohibits the movement of land rigs causing a high demand for rigs by a large number of companies during a relatively short period of time. Our future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on our financial condition and results of operations.
Our operations are also subject to all the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and natural gas, including unusual or unexpected geologic formations, pressures, down hole fires, mechanical failures, blowouts, explosions, uncontrollable flows of oil, natural gas or well fluids and pollution and other environmental risks. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. We participate in insurance coverage maintained by the operator of its wells, although there can be no assurances that such coverage will be sufficient to prevent a material adverse effect to us in such events.
The vast majority of our oil and natural gas reserves are classified as proved reserves. Recovery of the Company's future proved undeveloped reserves will require significant capital expenditures. Our management estimates that additional capital expenditures will be required to fully develop some of these reserves in the next twelve month period. No assurance can be given that our estimates of capital expenditures will prove accurate, that our financing sources will be sufficient to fully fund our planned development activities or that development activities will be either successful or in accordance with our schedule. Additionally, any significant decrease in oil and natural gas prices or any significant increase in the cost of development could result in a significant reduction in the number of wells drilled and/or reworked. No assurance can be given that any wells will produce oil or natural gas in commercially profitable quantities.
We are subject to uncertainties in reserve estimates and future net cash flows.
This annual report contains estimates of our oil and natural gas reserves and the future net cash flows from those reserves. These estimates have been prepared by Company personnel for 2014, 2013 and 2012. There are numerous uncertainties inherent in estimating quantities of reserves of oil and natural gas and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve estimates in this annual report are based on various assumptions, including, for example, constant oil and natural gas prices, operating expenses, capital expenditures and the availability of funds, and therefore, are inherently imprecise indications of future net cash flows. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this annual report. Additionally, our reserves may be subject to
downward or upward revision based upon actual production performance, results of future development and exploration, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
The present value of future net reserves discounted at 10% (the "PV-10") of proved reserves referred to in this annual report should not be construed as the current market value of the estimated proved reserves of oil and gas attributable to our properties. In accordance with applicable requirements of the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by: (i) the timing of both production and related expenses; (ii) changes in consumption levels; and (iii) governmental regulations or taxation. In addition, the calculation of the present value of the future net cash flows using a 10% discount as required by the SEC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas industry in general. Furthermore, our reserves may be subject to downward or upward revision based upon actual production, results of future development, supply and demand for oil and natural gas, prevailing oil and natural gas prices and other factors. See "Properties - Oil and Gas Reserves."
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.
Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may be unable to make such acquisitions because we are:
·unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
·unable to obtain financing for these acquisitions on economically acceptable terms; or
·outbid by competitors.
If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.
There are risks in acquiring producing oil and natural gas properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of management attention, increasing the scope, geographic diversity and complexity of our operations.
One of our business strategies includes growing our reserve base through acquisitions of oil & gas properties. Our failure to integrate acquired properties successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in unanticipated expenses and losses. In addition, we may assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.
We are continually investigating opportunities for acquisitions. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Our ability to make future acquisitions may be constrained by our ability to obtain additional financing.
Possible future acquisitions could result in our incurring debt, contingent liabilities and expense, all of which could have a material effect on our financial condition and operating results.
Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.
Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, recovery applicability from water flood and Enhanced Oil Recovery techniques (“EOR”), future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well or property. Even when we inspect a well or property, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. It is our current intention to continue focusing on acquiring properties with development and exploration potential located in onshore United States. To the extent that we acquire properties substantially different from the properties in our primary operating regions or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as in our prior acquisitions.
We cannot control activities on properties we do not operate. Failure to fund capital expenditure requirements may result in reduction or forfeiture of our interests in some of our non-operated projects.
We do not operate some of the properties in which we have an interest and we have limited ability to exercise influence over operations for these properties or their associated costs. As of December 31, 2014, approximately 22% of our crude oil and natural gas proved reserves were operated by other companies. Our dependence on other operators and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted return on capital in drilling or acquisition activities and our targeted production growth rate. The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond our control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of technology.
When we are not the majority owner or operator of a particular crude oil or natural gas project, we may have no control over the timing or amount of capital expenditures associated with such project. If we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.
We are subject to risks associated with the current United States Government Administration’s proposed budget features.
The Obama administration has set forth budget proposals which if passed, would significantly curtail our ability to attract investors and raise capital. Proposed changes in the Federal income tax laws which would eliminate or reduce the percentage depletion deduction and the deduction for intangible drilling and development costs for small independent producers, will significantly reduce the investment capital available to those in the industry as well as our Company. Lengthening the time to expense seismic costs will also have an adverse effect on our ability to explore and find new reserves.
We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.
Our oil and gas business involves a variety of operating risks, including, but not limited to, unexpected formations or pressures, uncontrollable flows of oil, natural gas, brine or well fluids into the environment (including groundwater contamination), blowouts, fires, explosions, pollution and other risks, any of which could result in personal injuries, loss of life, damage to properties and substantial losses. Although we carry insurance at levels that we believe are reasonable, we are not fully insured against all risks. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on our financial condition and operations.
From time to time, due primarily to contract terms, pipeline interruptions or weather conditions, the producing wells in which we own an interest have been subject to production curtailments. The curtailments range from production being partially restricted to wells being completely shut-in. The duration of curtailments varies from a few days to several months. In most cases, we are provided only limited notice as to when production will be curtailed and the duration of such curtailments. We are not currently experiencing any material curtailment of our production.
We intend to increase to some extent our development and, to a lesser extent, exploration activities. Exploration drilling and, to a lesser extent, development drilling of oil and gas reserves involve a high degree of risk that no commercial production will be obtained and/or that production will be insufficient to recover drilling and completion costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit on the investment or a recovery of drilling, completion and operating costs.
We depend on our key management personnel and technical experts and the loss of any of these individuals could adversely affect our business.
If we lose the services of our key management personnel, technical experts or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could suffer. We have assembled a team of engineers and geologists who have considerable experience in applying advanced drilling and completion techniques to explore for and to develop crude oil and natural gas. We depend upon the knowledge, skill and experience of these experts to assist us in improving the performance and reducing the risks associated with our participation in crude oil and natural gas exploration and development projects. In addition, the success of our business depends, to a significant extent, upon the abilities and continued efforts of our management, particularly Chris Mazzini, our Chief Executive Officer, President and Chairman of the Board. We do not have an employment agreement with or key-man life insurance on Mr. Mazzini or any of our other employees.
Certain of our affiliates control a majority of our outstanding common stock, which may affect your vote as a shareholder.
Our executive officers, directors and their affiliates hold approximately 85% of our outstanding shares of common stock. As a result, officers, directors and their affiliates and such shareholders have the ability to exert significant influence over our business affairs, including the ability to control the election of directors and results of voting on all matters requiring shareholder approval. This concentration of voting power may delay or prevent a potential change in control.
Certain of our affiliates have engaged in business transactions with the Company, which may result in conflicts of interest.
Certain officers, directors and related parties, including entities controlled by Mr. Mazzini, the President and Chief Executive Officer, have engaged in business transactions with the Company which were not the result of arm's length negotiations between independent parties. Our management believes that the terms of these transactions were as favorable to us as those that could have been obtained from unaffiliated parties under similar circumstances. All future transactions between us and our affiliates will be on terms no less favorable than could be obtained from unaffiliated third parties and will be approved by a majority of the disinterested members of our Board of Directors.
Our common stock is traded on the Over-the-Counter market and is currently quoted on the OTC Market (“OTC QB”), symbol "SPND". Effective May 1, the Company’s common stock will be traded on the “ OTC Pink” marketplace.
The liquidity of our common stock may be adversely affected, and purchasers of our common stock may have difficulty selling our common stock, if our common stock does not continue to trade in that or another suitable trading market.
There is presently only a limited public market for our common stock, and there is no assurance that a ready public market for our securities will develop. It is likely that any market that develops for our common stock will be highly volatile and that the trading volume in such market will be limited. The trading price of our common stock could be subject to wide fluctuations in response to quarter-to-quarter variations in our operating results, announcements of our drilling results and other events or factors. In addition, the United States stock market has from time to time experienced extreme price and volume fluctuations that have affected the market price for many companies and which often have been unrelated to the operating performance of these companies. These broad market fluctuations may adversely affect the market price of our securities.
We do not intend to declare dividends in the foreseeable future.
Our Board of Directors presently intends to retain all of our earnings for the expansion of our business. We therefore do not anticipate the distribution of cash dividends in the foreseeable future. Any future decision of our Board of Directors to pay cash dividends will depend, among other factors, upon our earnings, financial position and cash requirements.
We are subject to certain title risks.
Our company employees and contract land professionals have reviewed title records or other title review materials relating to substantially all of our producing properties. The title investigation performed by us prior to acquiring undeveloped properties is thorough, but less rigorous than that conducted prior to drilling, consistent with industry standards. We believe we have satisfactory title to all our producing properties in accordance with standards generally accepted in the oil and gas industry. 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 value of such properties. At December 31, 2014, our leaseholds for some of our net acreage were being kept in force by virtue of production on that acreage in paying quantities. The remaining net acreage was held by lease rentals and similar provisions and requires production in paying quantities prior to expiration of various time periods to avoid lease termination.
We expect to make acquisitions of oil and gas properties from time to time subject to available resources. In making an acquisition, we generally focus most of our title and valuation efforts on the more significant properties. It is generally not feasible for us to review in-depth every property we purchase and all records with respect to such properties. However, even an in-depth review of properties and records may not necessarily reveal existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their deficiencies and capabilities. Evaluation of future recoverable reserves of oil and gas, which is an integral part of the property selection process, is a process that depends upon evaluation of existing geological, engineering and
production data, some or all of which may prove to be unreliable or not indicative of future performance. To the extent the seller does not operate the properties, obtaining access to properties and records may be more difficult. Even when problems are identified, the seller may not be willing or financially able to give contractual protection against such problems, and we may decide to assume environmental and other liabilities in connection with acquired properties.
Our business is highly capital-intensive, requiring continuous development and acquisition of oil and gas reserves. In addition, capital is required to operate and expand our oil and natural gas field operations and purchase equipment. At December 31, 2014, we had working capital of $10,655,000. We anticipate that we will be able to meet our cash requirements for the next 12 months. However, if such plans or assumptions change or prove to be inaccurate, we could be required to seek additional financing sooner than currently anticipated.
We have funded our operations, acquisitions and expansion costs primarily through our internally generated cash flow. Our success in obtaining the necessary capital resources to fund future costs associated with our operations and expansion plans is dependent upon our ability to: (i) increase revenues through acquisitions and recovery of our proved producing and proved developed non-producing oil and gas reserves; and (ii) maintain effective cost controls at the corporate administrative office and in field operations. However, even if we achieve some success with our plans, there can be no assurance that we will be able to generate sufficient revenues to achieve significant profitable operations or fund our expansion plans.
We have substantial capital requirements necessary for undeveloped properties for which we may not be able to obtain adequate financing.
Development of our properties will require additional capital resources. We have no commitments to obtain any additional debt or equity financing and there can be no assurance that additional financing will be available, when required, on favorable terms to us. The inability to obtain additional financing could have a material adverse effect on us, including requiring us to curtail significantly our oil and gas acquisition and development plans or farm-out development of our properties. Any additional financing may involve substantial dilution to the interests of our shareholders at that time.
Oil and natural gas prices fluctuate widely and low prices could have a material adverse impact on our business and financial results.
Our revenues, profitability and the carrying value of our oil and gas properties are substantially dependent upon prevailing prices of, and demand for, oil and natural gas and the costs of acquiring, finding, developing and producing reserves. Our ability to obtain borrowing capacity, to repay future indebtedness, and to obtain additional capital on favorable terms is also substantially dependent upon oil and natural gas prices. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuations in response to: (i) relatively minor changes in the supply of, and demand for, oil and natural gas; (ii) market uncertainty; and (iii) a variety of additional factors, all of which are beyond our control. These factors include domestic and foreign political conditions, the price and availability of domestic and imported oil and natural gas, the level of consumer and industrial demand, weather, domestic and foreign government relations, the price and availability of alternative fuels and overall economic conditions. Furthermore, the marketability of our production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. Volatility in oil and natural gas prices could affect our ability to market our production through such systems, pipelines or facilities. As of December 31, 2014, approximately 77% of our oil and natural gas production is currently sold to 15 purchasing firms on a month-to-month basis at prevailing spot market prices. Oil prices remained subject to unpredictable political and economic forces during 2014, 2013, and 2012, and experienced fluctuations similar to those seen in natural gas prices for the year. We believe that oil prices will continue to fluctuate in response to changes in the policies of the Organization of Petroleum Exporting Countries ("OPEC"), changes in demand from many Asian countries, current events in the Middle East and Eastern Europe, security threats to the United States, and other factors associated with the world political and economic environment. As a result of the many uncertainties associated with levels of production maintained by OPEC and other oil producing countries, the availabilities of worldwide energy supplies and competitive relationships and consumer perceptions of various energy sources, we are unable to predict what changes will occur in crude oil and natural gas prices.
We may be responsible for additional costs in connection with abandonment of properties.
We are responsible for payment of plugging and abandonment costs on our oil and gas properties pro rata to our working interest. Based on our experience, we anticipate that in most cases, the ultimate aggregate salvage value of lease and well equipment located on our properties should equal to the costs of abandoning such properties. There can be no assurance, however, that we will be successful in avoiding additional expenses in connection with the abandonment of any of our properties. In addition, abandonment costs and their timing may change due to many factors, including actual production results, inflation rates and changes in environmental laws and regulations.
Risks that Involve the Oil & Gas Industry in General.
We are subject to various governmental regulations which may cause us to incur substantial costs.
Our operations are affected from time to time in varying degrees by political developments and federal, state, and local laws and regulations. In particular, oil and natural gas production-related operations are or have been subject to price controls, taxes and other laws and regulations relating to the oil and gas industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, because such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations.
Sales of natural gas by us are not regulated and are generally made at market prices. However, the Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by us, as well as the revenues received by us for sales of such production. Sales of our natural gas currently are made at uncontrolled market prices, subject to applicable contract provisions and price fluctuations that normally attend sales of commodity products.
Since the mid-1980s, the FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B ("Order 636"), that have significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of the FERC's purposes in issuing the orders was to increase competition within all phases of the natural gas industry. Order 636 and subsequent FERC orders issued in individual pipeline restructuring proceedings have been the subject of appeals, and the courts have largely upheld Order 636. Because further review of certain of these orders is still possible, and other appeals may be pending, it is difficult to exactly predict the ultimate impact of the orders on us and our natural gas marketing efforts. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines' traditional role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets.
While significant regulatory uncertainty remains, Order 636 may ultimately enhance our ability to market and transport our natural gas, although it may also subject us to greater competition, more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.
The FERC has announced several important transportation-related policy statements and proposed rule changes, including the appropriate manner in which interstate pipelines release capacity under Order 636 and, more recently, the price which shippers can charge for their released capacity. In addition, in 1995, the FERC issued a policy statement on how interstate natural gas pipelines can recover the costs of new pipeline facilities. In January 1997, the FERC issued a policy statement and a request for comments concerning alternatives to its traditional cost-of-service rate making methodology. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. While any additional FERC action on these matters would affect us only indirectly, these policy statements and proposed rule changes are intended to further enhance competition in natural gas markets. We cannot predict what the FERC will take on these matters, nor can we predict whether the FERC's actions will achieve its stated goal of increasing competition in natural gas markets. However, we do not believe that we will be treated materially differently than other natural gas producers and marketers with which we compete.
The price we receive from the sale of oil is affected by the cost of transporting such products to market. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. These regulations could increase the cost of transporting oil by interstate pipelines, although the most recent adjustment generally decreased rates. These regulations have generally been approved on judicial review. We are not able to predict with certainty the effect, if any, of these regulations on its operations. However, the regulations may increase transportation costs or reduce wellhead prices for oil.
The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration for and production of oil and natural gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of certain states limit the rate at which oil and gas can be produced from our properties. However, we do not believe we will be affected materially differently by these statutes and regulations than any other similarly situated oil and gas company.
We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure.
We maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We may elect not to carry insurance if our management believes that the cost of insurance is excessive relative to the risks presented. If an event occurs that is not covered, or not fully covered, by insurance, it could harm our financial condition, results of operations and cash flows. In addition, we cannot fully insure against pollution and environmental risks.
We are subject to various environmental risks which may cause us to incur substantial costs.
Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling and transportation of oil and natural gas and the discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, penalties or injunctions. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us. The impact of such changes, however, would not likely be any more burdensome to us than to any other similarly situated oil and gas company.
The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint
and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Furthermore, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We generate typical oil and gas field wastes, including hazardous wastes that are subject to the Federal Resources Conservation and Recovery Act and comparable state statutes. The United States Environmental Protection Agency and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our oil and gas operations that are currently exempt from regulation as "hazardous wastes" may in the future be designated as "hazardous wastes", and therefore be subject to more rigorous and costly operating and disposal requirements.
The Oil Pollution Act ("OPA") imposes a variety of requirements on responsible parties for onshore and offshore oil and gas facilities and vessels related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The "responsible party" includes the owner or operator of an onshore facility or vessel or the lessee or permittee of, or the holder of a right of use and easement for, the area where an onshore facility is located. OPA assigns liability to each responsible party for oil spill removal costs and a variety of public and private damages from oil spills. Few defenses exist to the liability for oil spills imposed by OPA. OPA also imposes financial responsibility requirements. Failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement actions.
We own or lease properties that for many years have produced oil and natural gas. We also own natural gas gathering systems. It is not uncommon for such properties to be contaminated with hydrocarbons. Although we or previous owners of these interests may have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties or on or under other locations where such wastes have been taken for disposal. These properties may be subject to federal or state requirements that could require us to remove any such wastes or to remediate the resulting contamination. In addition to properties that we operate, we have interests in many properties which are operated by third parties over whom we have limited control. Notwithstanding our lack of control over properties operated by others, the failure of the previous owners or operators to comply with applicable environmental regulations may, in certain circumstances, adversely impact us.
Item 1B.
Item 1B. Unresolved Staff Comments
None
Item 2.
Item 2. Properties
OIL AND GAS PROPERTIES
The following table sets forth pertinent data with respect to the Company-owned oil and gas properties, all located within the continental United States, as estimated by the Company:
(1) The estimate of the net proved oil and natural gas reserves, future net revenues, and the present value of future net revenues.
(2) "Proved Developed Oil and Natural gas Reserves" are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
(3) "Proved Undeveloped Reserves" are 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. See Footnote 18 to the Financial Statements, Supplemental Reserve Information (Unaudited), for further explanation of the changes for 2012 through. 2014.
(4) Reserve amounts are rounded to the nearest thousand.
Productive Wells
The following table sets forth our domestic productive wells and includes both operated wells and wells operated by third parties at December 31, 2014.
Acreage
The following table sets forth our undeveloped and developed gross and net leasehold acreage for our operated and non-operated wells at December 31, 2014. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. Undeveloped acreage should not be confused with undrilled acreage held by Production under the terms of a lease. Undrilled acreage held by production under the terms of a lease is included in the Developed Acreage category total shown below.
All the leases for the undeveloped acreage summarized in the preceding table will expire at the end of their respective primary terms unless prior to that date, the existing leases are renewed or production has been obtained from the acreage subject to the lease, in which event the lease will remain in effect until the cessation of production. As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defect or from defects in the assignment of leasehold rights.
Wells Drilled and Completed
The Company's working interests in both operated and outside operated exploration and development wells completed during the years indicated were as follows:
(1) An exploratory well is a well drilled to find and produce oil or natural gas in an unproved area, 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.
(2) A development well is 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.
The following tables set forth additional data with respect to production from Company-owned oil and gas operated and non-operated properties, all located within the continental United States:
(1) Includes severance taxes and ad valorem taxes.
(2) Natural gas production is converted to equivalent barrels at the rate of six MCFG per barrel, representing relative energy content of natural gas to oil.
The Company owns producing royalties and overriding royalties under properties located in Texas. The revenue from these properties is not significant.
The Company is not aware of any major discovery or other favorable or adverse event that is believed to have caused a significant change in the estimated proved reserves since December 31, 2014.
OFFICE SPACE
The Company owns a commercial office building. The property is a two story multi-tenant, garden office building with a sub-grade parking garage. The 33 year old building contains approximately 46,286 rentable square feet and sits on a 1.4919 acre block of land situated in north Dallas, Texas in close proximity to hotels, restaurants and shopping areas (the Galleria Mall) with easy access to Interstate Highway 635 (LBJ Freeway) and Dallas Parkway (North Dallas Toll Road). The Company occupies approximately 12,759 rentable square feet of the building as its primary office headquarters, and leases the remaining space in the building to non-related third party commercial tenants at prevailing market rates.
The address of the Company's principal executive offices is One Spindletop Centre, 12850 Spurling Road, Suite 200, Dallas, Texas 75230. The telephone number is (972) 644-2581.
PIPELINES
The Company owns, through its subsidiary, PPC, 26.1 miles of natural gas pipelines in Parker, Palo Pinto and Eastland Counties, Texas. These pipelines are steel and polyethylene and range in size from two inches to four inches. These pipelines primarily gather natural gas from wells operated by the Company and in which the Company owns a working interest, but also for other parties.
The Company normally does not purchase and resell natural gas, but gathers natural gas for a fee. The fees charged in some cases are subject to regulations by the State of Texas and the Federal Energy Regulatory Commission. Average daily volumes of natural gas gathered by the pipelines owned by the Company were 1,063, 1,096, and 1,345, mcfgpd for 2014, 2013, and 2012, respectively.
Oilfield Production Equipment
The Company owns various natural gas compressors, pumping units, dehydrators and various other pieces of oil field production equipment.
Substantially all of the equipment is located on oil and gas properties operated by the Company and in which it owns a working interest. The rental fees are charged as lease operating fees to each property and each owner.
M-R Oilfield Services, LP, is an oilfield service company which provides roustabout, swabbing and completion services to the Company at rates which are at or below market. This limited partnership has Chris G. Mazzini and Michelle H. Mazzini as its limited partners. This oilfield services company currently does work exclusively for the Company and its related company, Giant Energy Corp., although it has contemplated doing work for unrelated third parties as well. The Company benefits by having immediate access to services.
Item 3.
Item 3. Legal Proceedings
Neither the Registrant nor its subsidiaries nor any officers or directors is a party to any material pending legal proceedings for or against the Company or its subsidiaries, nor are any of their properties subject to any proceedings.
During the fourth quarter of the fiscal year covered by this report, no proceeding previously reported was terminated.
Item 4.
Item 4. Mine Safety Disclosures
Not Applicable
PART II
Item 5.
Item 5. Market For The Company's Common Stock, Related Stockholder Matters And Issuer Purchases Of Equity Securities.
The Company's common stock trades Over-The-Counter under the symbol "SPND".
Prior to 2004, no significant public trading market had been established for the Company's common stock. The Company does not believe that listings of bid and asking prices for its stock are indicative of the actual trades of its stock, since trades are made infrequently. The following table shows high and low trading prices for each quarter in 2014, 2013, and 2012.
There is no amount of common stock that is subject to outstanding warrants to purchase, or securities convertible into, common stock of the Company.
According to the transfer records of the Company at April 15, 2015, common stock of the Company was held by approximately 540 known holders of record.
The following chart compares the yearly percentage change in the cumulative total stockholder return on the Company's Common Stock during the five years ended December 31, 2014 with the cumulative total return of the Standard and Poor's 500 Stock Index and of the Dow Jones U.S. Exploration and Production Index (formerly Dow Jones Secondary Oil Stock Index). The comparison assumes $100 was invested on December 31, 2009 in the Company's Common Stock and in each of the foregoing indices and assumes reinvestment of dividends. The Company paid no dividends on its Common Stock during the five-year period. Figures shown are past results and are not predictive of results in future periods.
Stock Performance Chart
Comparison of Five-Year Cumulative Total Return Among
Spindletop Oil & Gas Co., S&P 500 Index and
the Dow Jones U.S. Exploration and Production Index
The Company has not paid any dividends since its reorganization and it is not contemplated that it will pay any dividends on its Common Stock in the foreseeable future.
The Registrant currently serves as its own stock transfer agent and registrar.
The Company has not approved nor authorized any standing repurchase program for its common stock.
During the fourth quarter of the fiscal year ended December 31, 2012, the Company made the following repurchases of its common stock:
Effective October 30, 2012, the Company repurchased 700,000 shares of its common stock for a purchase price of $1,491,000 or $2.13 per share.
On December 18, 2012, the Company repurchased 24,534 shares of its common stock for a purchase price of $36,801 or $1.50 per share.
The Company made no repurchases of its common stock during 2013 and 2014.
The repurchased shares are held as Treasury Stock.
Item 6.
Item 6. Selected Financial Data
The selected financial information presented should be read in conjunction with the consolidated financial statements and the related notes thereto.
Item 7.
Item 7. Management's Discussion And Analysis Of Financial Condition And
Results Of Operations
Liquidity and Capital Resources
The Company's operating capital needs, as well as its capital spending program, are generally funded from cash flow generated by operations. Because future cash flow is subject to a number of variables, such as the level of production and the sales price of oil and natural gas, the Company can provide no assurance that its operations will provide cash sufficient to maintain current levels of capital spending. Accordingly, the Company may be required to seek additional financing from third parties in order to fund its exploration and development programs.
Results of Operations
2014 Compared to 2013
Oil revenue for 2014 was approximately $8,317,000 compared to $9,471,000 for 2013, a decrease of approximately $1,154,000 or 12.2%. Average oil prices decreased to an average of $93.38 per barrel in 2014 from an average of $105.38 per bbl in 2013, a decrease of $12.00 per bbl or 11.4%. Oil sales decreased to 89,068 bbls from approximately 89,872 bbls in 2013, a decrease of 804 bbls or 0.9%. The decrease in oil revenue and sales is predominantly due the significant decreases in crude oil prices beginning in the second half of 2014.
Natural gas revenue for 2014 was approximately $3,371,000 compared to $2,986,000 for 2013, an increase of approximately $385,000 or 12.9%. Natural gas sales increased to approximately 740,000 mcf in 2014 from approximately 737,000 mcf in 2013, an increase of approximately 3,000 mcf or 0.5%. Natural gas prices increased to an average of $4.53 per mcf in 2014, an increase of $0.48 or 11.9% from an average of $4.05 per mcf in 2013.
Revenue from lease operations was $481,000 for 2014, an increase of $72,000 or 17.6% from $409,000 in 2013. This was due primarily to an increase in field supervision charges on operated wells of approximately $31,000 as a result of workover activity during 2014. In addition there was an increase in administrative overhead billed to working interest owners of approximately $41,000 due primarily to an increase in COPAS overhead rates billed.
Revenues from gas gathering, compression and equipment rental for 2014 was $155,000, an increase of $13,000 or 9.2% from $142,000 in 2013. This was due primarily to an increase in natural gas volume sold through PPC.
Real estate rental revenue for 2014 was $240,000, down 3.6% or $9,000 from $249,000 in 2013.
Interest income for 2014 was approximately $125,000, an increase of approximately $44,000 from approximately $81,000 in 2013 or 54.3%. Although overall interest rates on deposit accounts at most of the banking institutions at which the Company is a depositor have decreased over prior years, the Company’s increased cash balances have yielded higher interest income.
Other revenue for 2014 was $519,000, as compared to $209,000 in 2013, an increase of $310,000 or 148%. This change is due primarily to the recognition of fees earned under drilling ventures. In addition, there was a decrease in the amount of cash received for farm-out agreements in 2014 over that received during 2013. From time to time, the Company farms out some of its leasehold acreage to non-affiliated third parties for exploration and development drilling. Generally, the Company receives a one-time payment for the agreement. The revenues from these farm-out agreements vary in size and frequency and should not be considered as regularly recurring revenues that the Company receives.
Lease operating expenses in 2014 were approximately $2,240,000 as compared to $2,524,000 in 2013, a net decrease of $284,000, or 11.3%. Of this net decrease, approximately $394,000 was due to decreased workover expenses on operated properties between periods, and approximately $71,000 was due to material credits transferred from various leases; both decreases were offset by approximately $86,000 attributable to new operated properties added since 2013, approximately $75,000 in increased operating expenses for non-operated leases, and the remaining $20,000 represented net increases and decreases on various properties due to general price fluctuations and levels of operation activity. The majority of the increase in operating expenses for non-operated leases was due to an agreement reached and recorded with an operator regarding lease operating expenses on multiple wells for multiple periods.
Production taxes, gathering, and marketing expenses for 2014 were approximately $996,000 compared to $1,001,000 in 2013, a decrease of approximately $5,000, or 0.5%. This decrease was directly related to the decrease in oil and natural gas production and revenues, which have been partially offset by an overall increase in gas severance tax on operated properties, caused by the expiration of certain severance tax exemptions, as well as increased expenses for non-operated leases.
Pipeline and rental expenses for 2014 were $49,000 compared to $42,000 for 2013, an increase of $7,000, or 16.7%. This increase is primarily due to repairs and maintenance expense.
Real estate expenses in 2014 were approximately $220,000 compared to $215,000 during the same period in 2013, an increase of approximately $5,000 or 2.3%.
Depreciation and amortization expense for 2014 was $1,846,000 compared to $1,913,000 for 2013, a decrease of $67,000, or 3.5%. The Company re-evaluated its proved oil and gas reserves as of December 31, 2014, and decreased its estimated total proved reserves by approximately 33,000 BOE to 1,544,000 BOE at the end of 2014 compared to 1,577,000 BOE at the end of 2013, a decrease of approximately 2.1%. Sales of oil and natural gas products during 2014 decreased by approximately 1,000 BOE from approximately 213,000 BOE in 2013 to approximately 212,000 BOE in 2014, a decrease of approximately 0.5%. (See Footnote 18 to the Financial Statements). This resulted in a decrease in the depletion rate factor from 13.395% in 2013 on an unamortized full cost pool base of $13,752,000 to a depletion rate factor of 12.090% on an unamortized full cost pool base of $14,650,000 in 2014. The net increase in the unamortized full cost pool base of $898,000 was due primarily to an increase in the amounts capitalized in the full cost pool of approximately $2,740,000 less the increase in accumulated depletion of $1,842,000.
Asset Retirement Obligation (“ARO”) accretion expense for 2014 was $42,000 down from $118,000 in 2013; a decrease of $76,000 or 64.4%. The ARO calculation is based on the Company’s annual reserve report and takes into consideration the changes between years of the Company’s estimated obligation to plug its interest in existing wells. This estimated future cost is discounted using a 10% discount factor based on the estimated life of each property. Changes are incorporated as applicable into the full cost pool and the carrying value of the liability. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.
General and administrative expenses for 2014 were approximately $4,019,000 as compared to approximately $3,648,000 for 2013, an increase of approximately $371,000 or 10.2%. The increase was primarily due to increased salary, wages and employee benefits as several new employees have been added in 2014.
The Company incurred no interest expense for 2014 compared to approximately $17,000 for 2013, a decrease of approximately $17,000. Effective December 27, 2013, the Company prepaid the remaining principal plus accrued interest on its bank loan for the Company’s office building.
2013 Compared to 2012
Oil revenue for 2013 was approximately $9,471,000 compared to $7,116,000 for 2012, an increase of approximately $2,355,000 or 33%. Oil prices increased to an average of $105.38 per barrel in 2013 from an average of $89.49 per bbl in 2012, an increase of $15.89 per bbl or 18%. Oil sales increased to 89,872 bbls from approximately 79,514 bbls in 2012, an increase of 10,358 bbls or 13%. The increase in oil revenue and sales is predominantly due to participation in new wells during 2013.
Natural gas revenue for 2013 was approximately $2,986,000 compared to $2,882,000 for 2012, an increase of approximately $104,000 or 4%. Natural gas sales decreased to approximately 737,000 mcf in 2013 from approximately 792,000 mcf in 2012, a decrease of 55,000 mcf or 7%. Natural gas prices increased to an average of $4.05 per mcf in 2013, an increase of $0.41 or 11% from an average of $3.64 per mcf in 2012.
Revenue from lease operations was $409,000 for 2013, an increase of $50,000 or 14% from $359,000 in 2012. This was due primarily to an increase in field supervision charges on operated wells of approximately $14,000 as a result of workover activity during 2013. In addition there was an increase in administrative overhead billed to working interest owners of approximately $36,000 due primarily to an increase in COPAS overhead rates billed.
Revenue from natural gas gathering for 2013 was $142,000, a decrease of $3,000 or 2% from $145,000 in 2012. This was due primarily to a decrease in natural gas volume sold through PPC.
Real estate income for 2013 was $249,000, up 3% or $7,000 from $242,000 in 2012. This was due to an increase in leasing activity over 2012.
Interest income for 2013 was approximately $81,000, an increase of approximately $3,000 from approximately $78,000 in 2012 or 4%. Although overall interest rates on deposit accounts at most of the banking institutions at which the Company is a depositor have decreased over prior years, the Company’s increased cash balances have yielded higher interest income.
Other income for 2013 was $209,000, as compared to $1,284,000 in 2012, a decrease of $1,075,000 or 84%. This change is due to the decrease in cash received for farm-out agreements in 2013 over that received during 2012. From time to time, the Company farms out some of its leasehold acreage to non-affiliated third parties for exploration and development drilling. Generally, the Company receives a one-time payment for the agreement. The revenues from these farm-out agreements vary in size and frequency and should not be considered as regularly recurring revenues that the Company receives.
Lease operations expense for 2013 was $2,524,000 as compared to $2,631,000 in 2012, a net decrease of approximately $107,000, or 4%. Of this net decrease, approximately $125,000 is due to decreased workover activity, approximately $78,000 is due to new properties added since 2012, and a reduction of approximately $31,000 is due to a decrease in expenses from non-operated properties. The remaining $28,000 represents net increases and decreases on various properties due to general price increases and changes in levels of workover activity.
Production taxes, gathering, transportation and marketing expenses for 2013 were approximately $1,001,000 compared to $891,000 in 2012, a net increase of $110,000. This 12% net increase is the result of an increase in severance taxes based on the increase in oil revenues.
Pipeline and rental operation expenses were approximately $42,000 in 2013 compared to approximately $26,000 in 2012, an increase of approximately $16,000 or 62%. This was due mainly to an increase in the costs associated with compressor and pipeline repairs, as well as maintenance costs.
Real estate operations expenses for 2013 were $215,000, up from $185,000 in 2012. This 16% increase of $30,000 was primarily due to increased interior and exterior maintenance of approximately $25,000 as well as higher utilities costs of approximately $5,000.
Depreciation and amortization expense for 2013 was $1,913,000 compared to $1,647,000 for 2012, an increase of $266,000, or 16%. The Company re-evaluated its proved oil and gas reserves as of December 31, 2013, and decreased its estimated total proved reserves by approximately 11,000 BOE to 1,577,000 BOE at the end of 2013 compared to 1,588,000 BOE at the end of 2012, a decrease of approximately 1%. Sales of oil and natural gas products during 2013 increased by approximately 2,000 BOE from approximately 211,000 BOE in 2012 to approximately 213,000 BOE in 2013, an increase of approximately 1%. (See Footnote 18 to the Financial Statements). This resulted in an increase in the depletion rate factor from 11.754% in 2012 on an unamortized full cost pool base of $13,464,000 to a depletion rate factor of 13.395% on an unamortized full cost pool base of $13,752,000 in 2013. The net increase in the unamortized full cost pool base of $288,000 was due primarily to an increase in the amounts capitalized in the full cost pool of approximately $1,870,000 less the increase in accumulated depletion of $1,582,000.
Asset Retirement Obligation (“ARO”) accretion expense for 2013 was $118,000 up from $40,000 in 2012; an increase of $78,000 or 195%. The ARO calculation is based on the Company’s annual reserve report and takes into consideration the changes between years of the Company’s estimated obligation to plug its interest in existing wells. This estimated future cost is discounted using a 10% discount factor based on the estimated life of each property. Changes are incorporated as applicable into the full cost pool and the carrying value of the liability. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.
General and administrative expenses for 2013 were $3,648,000 compared to $3,719,000 for 2012, a decrease of approximately $71,000 between years or 2%. This decrease is due mainly to payroll and associated employee benefit costs during 2013.
Interest expense for 2013 was $17,000, down from $29,000 in 2012; a decrease of $12,000 or 41%. The reason for the reduction is the decreasing balance on the loan for the Company’s office building on which interest is paid. The interest rate on the loan was adjusted from 6.11% in December 2011 to 3.61% for future years. Effective December 27, 2013, the Company prepaid the remaining principal balance plus accrued interest and the note was paid in full.
Certain Factors That Could Affect Future Operations
Certain information contained in this report, as well as written and oral statements made or incorporated by reference from time to time by the Company and its representatives in other reports, filings with the Securities and Exchange Commission, press releases, conferences, teleconferences or otherwise, may be deemed to be 'forward-looking statements' within the meaning of Section 21E of the Securities Exchange Act of 1934 and are subject to the 'Safe Harbor' provisions of that section.
Forward-looking statements include statements concerning the Company's and management's plans, objectives, goals, strategies and future operations and performance and the assumptions underlying such forward-looking statements. When used in this document, the words "anticipates", "estimates", "expects", "believes", "intends", "plans", and similar expressions are intended to identify such forward-looking statements. Actual results and developments could differ materially from those expressed in or implied by such statements due to these and other factor.
Item 8.
Item 8. Consolidated Financial Statements and
Schedules Index at Page
Item 9.
Item 9. Changes In And Disagreements With Accountants On Accounting And Financial Disclosure
None
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial and Accounting Officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e)) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which 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 recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Principal Executive Officer and Principal Financial and Accounting Officer, as appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, our Principal Executive Officer and Principal Financial and Accounting Officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. There are inherent limitations to the effectiveness of any system of internal control over financial reporting. These limitations include the possibility of human error, the circumvention of overriding of the system and reasonable resource constraints. Because of its inherent limitations, our internal control over financial reporting may not prevent or detect misstatements. 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 policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2014. In making this assessment, management used the criteria set forth in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on management’s assessments and those criteria, management has concluded that Company’s internal control over financial reporting was effective as of December 31, 2014.
This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial report. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.
Changes in Internal Control over Financial Reporting
In preparation for management’s report on internal control over financial reporting, we documented and tested the design and operating effectiveness of our internal control over financial reporting. There were no changes in our internal controls over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information
Not Applicable
PART III
Item 10.
Item 10. Directors and Executive Officers Of The Registrant
The Directors and Executive Officers of the Company and certain information concerning them is set forth below:
Name Age Position
Chris G. Mazzini Chairman of the Board, Director and President
Michelle H. Mazzini Director, Vice President, Secretary, Treasurer
Ted R. Munselle Director
On January 2, 2012, Mr. David E. Allard, resigned as a member of the Board of Directors of Spindletop Oil & Gas Co.
On February 17, 2012, Mr. Ted R. Munselle was appointed as a member of the Board of Directors of Spindletop Oil & Gas Co. Mr. Munselle is determined to have all the credentials and qualifications to be an Independent Financial Expert and has been appointed as an Independent Financial Expert for the Audit Committee of the Board of Directors and has been appointed as Chairman of the Audit Committee.
Except as set forth above, all directors hold offices until the next annual meeting of the shareholders or until their successors are duly elected and qualified. Officers of the Company serve at the discretion of the Board of Directors.
Business Experience
Chris Mazzini, Chairman of the Board of Directors and President, graduated from the University of Texas at Arlington in 1979 with a Bachelor of Science degree in Geology. He started his career in the oil and gas industry in 1978, and began as a Petroleum Geologist with Spindletop in 1979, working the Fort Worth Basin of North Texas. He became Vice President of Geology at Spindletop in 1982 and served in that capacity until he left the Company in 1985 when he founded Giant Energy Corp. ("Giant"). Mr. Mazzini has served as President of Giant since then. He rejoined the Company in December 1999 when he, through Giant, purchased controlling interest. Mr. Mazzini has been Chairman of the Board of Directors and President of the Company since 1999 and is a Certified and Licensed Petroleum Geologist. Mr. Mazzini has worked numerous geological basins throughout the United States with an emphasis on the Fort Worth Basin. He is responsible for several new field discoveries in the Fort Worth Basin.
Michelle Mazzini, Vice President and General Counsel, received her Bachelor of Science Degree in Business Administration (Major: Accounting) from the University of Southwestern Louisiana (now named University of Louisiana at Lafayette) where she graduated magna cum laude in 1985. She earned her law degree from Louisiana State University where she graduated Order of the Coif in 1988. Ms. Mazzini began her career with Thompson & Knight, a large law firm in Dallas, where she focused her practice on general corporate and finance transactions. She also worked as Corporate Counsel for Alcatel USA, a global telecommunications manufacturing corporation where her practice was broad-based. Ms. Mazzini serves as Vice President and General Counsel of the Company.
On February 17, 2012, Mr. Ted R. Munselle was appointed as a member of the Board of Directors of Spindletop Oil & Gas Co. Mr. Munselle is Vice President and Chief Financial Officer (since October 1998) of Landmark Nurseries, Inc. He is a Certified Public Accountant (since 1980) who was employed as an Audit Partner in two Dallas, Texas based CPA firms (1986 to 1998), as an Audit Manager at Grant Thornton, LLP (1983 to 1986) and as Audit Staff to Audit Supervisor at Laventhol & Horwath (1977 to 1983). Mr. Munselle is also a director (since February 2004) of American Realty Investors, Inc. and Transcontinental Realty Investors, Inc., both of which are Nevada corporations which have their common stock listed and traded on the New York Stock Exchange (“NYSE”), as well as a director (since May 2009) of Income Opportunity Realty Investors, Inc., a Nevada corporation which has its common stock listed and traded on the NYSE MKT.
Key and Technical Employees
In addition to the services provided by Mr. Mazzini and Ms. Mazzini (both of whom have biographies listed above), the Company also relies extensively on the key and the technical employees identified below.
Michael G. Boos, Geologist, earned a Bachelor of Science degree in Geology from the University of Delaware in 1979. After performing geophysical research for the State of Delaware seeking hydrothermal energy sources, Mr. Boos worked independently for many years as a Petroleum Exploration Consultant and as a Staff Explorationist for a local oil company. He has numerous field discoveries in the Mid-Continent to his credit. In 1993 Mr. Boos joined Spindletop’s Geological Department. He pursued a Masters degree through the University of Texas system, and later worked as a Geologist and Senior Project Manager for several national environmental consulting firms until rejoining Spindletop in October, 2008. His petroleum exploration experience includes Alaska’s North Slope (Prudhoe Bay), many of the continental U.S. producing basins, as well as Central and South America. He has testified as an expert witness before the Texas Railroad Commission (TRRC) on several occasions. He is a founding member of both the Geological Information Library of Dallas (GILD, now Geomap) and the American Association of Petroleum Geologists (AAPG) Environmental Division, and is a licensed Professional Geologist (P.G.) in the states of Texas and Tennessee.
Dave Chivvis, Petroleum Engineer, joined the Company in May, 2008. Mr. Chivvis earned his Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1993. After graduation, he worked for Cox Resources Corporation, an independent oil and gas company located in Dallas, Texas. Mr. Chivvis worked in various engineering areas from operations to acquisitions of oil and gas properties in Texas, Oklahoma, Louisiana, and Arkansas. He then moved to Los Angeles in 2001 to pursue other opportunities before moving back to Texas to join the Company.
Robert E. Corbin, Controller, has been a full-time employee of Spindletop since April 2002. From May 2001 until April 2002, Mr. Corbin was an Independent Accounting Consultant and devoted substantially all of his time to Spindletop. He has been active in the oil and gas industry for over 39 years, during which time he has served as financial officer of a publicly-held company as well as several private oil and gas companies and partnerships. Mr. Corbin graduated from Texas Tech University in 1969 with a BBA degree in Accounting and began his accounting career as an auditor with Arthur Andersen & Co. in 1970. Mr. Corbin is a Certified Public Accountant since 1972.
Charles (Chuck) D. Howell, Jr., Geologist, joined the Company in April, 2008. Mr. Howell earned a Bachelor of Science in Geology from Southern Methodist University in 1999. Currently, he is finishing his Ph.D. in Geology at the University of Texas at Dallas. Mr. Howell has been in the energy industry since 2003. He began his career at Pioneer Natural Resources working in the Gulf of Mexico. During 2005, Mr. Howell was an Independent Consulting Geologist for Anadarko Petroleum Corporation and worked on development of the historic Salt Creek Oil Field. In 2007, immediately before joining Spindletop Oil and Gas Company, he was a Geologist for Chevron Energy Technology Company in Houston, Texas and was part of a team of stratigraphic specialists for the West Coast of Africa. Mr. Howell is a long-standing and active member of the American Association of Petroleum Geologists, the Society for Sedimentary Geology, the Geological Society of America, the International Association of Sedimentologists, and remains associated with the Ichnology Research Group.
Dick A. Mastin, Petroleum Landman, has been a full-time employee of the Company since February, 2006. Mr. Mastin graduated cum laude from Stephen F. Austin State University in 1980 with a Bachelor of Science in Forestry and a minor in General Business. From September of 1980 until December of 1985, Mr. Mastin worked for Spindletop Oil & Gas Co. as a Petroleum Landman. He received his Masters of Science in Management and Administrative Sciences from the University of Texas at Dallas in 1990. In January of 1987, he took a position with the Dallas office of the Federal Bureau of Investigation. After a year with the Bureau, he accepted a position with the Internal Revenue Service as a Revenue Agent. Fifteen of his eighteen years with the Service were spent in the Large and Mid-Sized Business unit auditing tax returns of the largest business entities.
Glenn E. Sparks is the Land Director and also acts as Associate General Counsel to the Company. Mr. Sparks was previously employed as a Landman by the Company from 1982 through 1986, prior to attending law school. Mr. Sparks holds a B.B.A. with a concentration in Finance from the University of Texas at Arlington, and a J.D. from Texas Tech University School of Law. From 1990 to 2005, Mr. Sparks practiced law in a private practice focusing primarily on oil and gas law and real estate, as a partner in the law firm of Logan & Sparks, PLLC, and has acted as outside legal counsel for the Company in numerous oil and gas transactions during his years in private practice. Mr. Sparks left his private law practice and joined the Company again as an employee in his current position in 2005. Mr. Sparks is Board Certified in Oil & Gas Mineral Law by the Texas Board of Legal Specialization.
Family Relationships
Michelle Mazzini, Vice President, Secretary and General Counsel is the wife of Chris Mazzini, Chairman of the Board and President.
Involvement in Certain Legal Proceedings
None of the directors or executive officers of the Registrant, during the past five years, has been involved in any civil or criminal legal proceedings, bankruptcy filings or has been the subject of an order, judgment or decree of any Federal or State authority involving Federal or State securities laws.
Board Meetings and Committees
The Board of Directors met one time in 2014. The Board has established an audit committee. The Board is small and all members of the Board serve on the audit committee. The function of the audit committee is to assist the Board in fulfilling its oversight responsibilities by reviewing the financial information that will be provided to the shareholders and others, the systems of internal controls that management and the Board of Directors have established, and the audit process. During 2011, the audit committee was comprised of Mr. David Allard (Chairman), Mr. Chris Mazzini, and Ms. Michelle Mazzini. Subsequent to December 31, 2011, Mr. Allard resigned as a member of the Board of Directors and as Chairman of the Audit Committee.
Effective with his appointment as a member of the Board of Directors of the Company on February 17, 2012, Mr. Ted Munselle assumed the position of Chairman of the Audit Committee. During 2014, Mr. Munselle was Chairman of the Audit Committee.
With respect to nominations to the Board, compensation, financial planning, strategies, and business alternatives, the Company does not have separate committees as the Board is small and all members of the Board participate in making recommendations and decisions on these matters.
Item 11.
Item 11. Executive Compensation
Cash Compensation
Cash compensation including salaries and bonuses, of $326,539, $349,405, and $415,132 was paid to Mr. Mazzini in 2014, 2013, and 2012 respectively. Cash compensation including salaries and bonuses of $209,424, $226,185, and $281,950 was paid to Ms. Mazzini in 2014, 2013, and 2012 respectively.
The Company has no stock option or incentive plan, does not grant any plan-based awards or awards of equity securities. The Company has no pension plan for its employees.
Compensation Pursuant to Plan
None
Other Compensation
Key employees and officers of the Company may sometimes be assigned overriding royalty interests and/or carried working interests in prospects acquired by or generated by the Company. These interests normally vary from less than one percent to three percent for each employee or officer. There is no set formula or policy for such program, and the frequency and amounts are largely controlled by the economics of each particular prospect. We believe that these types of compensation arrangements enable us to attract, retain and provide additional incentives to qualified and experienced personnel.
Compensation of Directors
Directors who are employees of the Company are not currently compensated for their services on the Board. Mr. Munselle was paid a director’s fee of $10,000 in 2014, $10,000 in 2013 and $10,000 in 2012 to compensate him for his position as the Board of Directors’ Financial Expert. Mr. Munselle also receives $2,500 for each Board of Directors’ meeting during the year other than the annual meeting. Mr. Munselle was paid a total of $10,000 in 2014, $10,000 in 2013 and $12,500 in 2012.
Termination of Employment and Change of Control Arrangement
There are no plans or arrangements for payment to officers or directors upon resignation or a change in control of the Registrant.
Item 12.
Item 12. Security Ownership Of Certain Beneficial Owners And Management
Security Ownership of Certain Beneficial Owners and Managers
The table below sets forth the information indicated regarding ownership of the Registrant's common stock, $.01 par value, the only outstanding voting securities, as of April 15, 2015 with respect to: (i) any person who is known to the Registrant to be the owner of more than five percent of the Registrant's common stock; (ii) the common stock of the Registrant beneficially owned by each of the directors of the Registrant, and (iii) by all officers and directors as a group. Each person has sole investment and voting power with respect to the shares indicated, except as otherwise set forth in the footnotes to the table.
* “Beneficial Ownership” means the sole or shared power to vote, or direct the voting of, a security or investment power with respect to a security, or any combination thereof.
** Percentages are based upon 6,936,269 shares of Common Stock outstanding at April 15, 2015.
(1) Chris Mazzini directly owns 39,654 shares (0.5717%). Giant Energy Corp. directly owns 5,860,889 shares (84.4963%). Chris Mazzini owns 100% of the common stock of Giant Energy Corp.
Changes in control
The Company is not aware of any arrangements or pledges with respect to its securities that may result in a change in control of the Company.
Item 13.
Item 13. Certain Relationships And Related Transactions
Transactions with management and others
Certain officers, directors and related parties, including entities controlled by Mr. Mazzini, the President and Chief Executive Officer, have engaged in business transactions with the Company which were not the result of arm's length negotiations between independent parties. Our management believes that the terms of these transactions were as favorable to us as those that could have been obtained from unaffiliated parties under similar circumstances. All future transactions between us and our affiliates will be on terms no less favorable than could be obtained from unaffiliated third parties and will be approved by a majority of the disinterested members of our Board of Directors.
Chris G. Mazzini and Michelle H. Mazzini, through a limited partnership in which they are limited partners, own M-R Oilfield Services, LP ("MRO"), an oilfield service company which provides roustabout, swabbing and completion services at rates which are at or below market to the Company. This oilfield services company currently does work exclusively for the Company, its parent company, Giant Energy Corp. and Giant NRG, LP, although MRO is contemplating offering its services to unrelated third-parties. The Company benefits by having immediate access to services. Effective January 1, 2014, MRO began leasing its employees from the Company.
Certain Business Relationships
The long-term debt, which was secured by the commercial office building, was also guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini, related parties. Effective December 27, 2013, the Company prepaid the remaining principal balance plus accrued interest and the note was paid in full.
On October 1, 2008, Giant entered into an Administrative Services Agreement with the Company whereby Giant pays the Company $250 per month for the Company providing administrative services to Giant. The Company has entered into a management services agreement with MRO whereby MRO makes monthly payments in the amount of $1,000 per month to the Company in exchange for the Company providing administrative services to MRO. On October 1, 2008, the Company entered into a similar agreement with Giant NRG, LP (“NRG”) a limited partnership with Chris Mazzini and Michelle Mazzini as limited partners. Under this agreement NRG pays a monthly fee of $2,500 to the Company in exchange for the Company providing certain administrative services to NRG. The Company has entered into a similar arrangement with Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly charge of $250 in exchange for the Company providing administrative services to Peveler. Chris and Michelle Mazzini are the owners of Peveler Pipeline, LP, a limited partnership which owns a pipeline gathering system servicing wells owned by Giant, another related entity, described elsewhere in this report. The Company entered into a similar agreement with M-R Ventures, LLC (“MRV”) a limited liability company that operates some wells in Michigan, and that is owned by Chris and Michelle Mazzini. Pursuant to this agreement, MRV pays the Company a monthly fee in the amount of $500 for certain administrative services that the Company provides to MRV. The Company entered into a similar agreement with Reserve Royalty Company (“Reserve”) a sole proprietorship that holds some royalty interests owned by Chris and Michelle Mazzini. Pursuant to this agreement, Reserve pays the Company a monthly fee in the amount of $350 for certain administrative services that the Company provides to Reserve. See also note 6 to the Financial Statements.
Item 14.
Item 14. Principal Accounting Fees and Services
The following table sets forth the aggregate fees for professional services rendered to Spindletop Oil & Gas Co. and Subsidiaries for the years 2014 and 2013 by accounting firm, Farmer, Fuqua, & Huff, P.C.
Members of the Board of Directors (the "Board") fulfill the responsibilities of an audit committee and have established policies and Procedures for the approval and pre-approval of audit services and permitted non-audit services. The Board has the responsibility to engage and terminate Farmer, Fuqua, & Huff, P.C. independent auditors, to pre-approve their performance of audit services and permitted non-audit services, to approve all audit and non-audit fees, and to set guidelines for permitted non-audit services and fees. All the fees for 2014 and 2013 were pre-approved by the Board or were within the pre-approved guidelines for permitted non-audit services and fees established by the Board, and there were no instances of waiver of approved requirements or guidelines during the same periods.
PART IV
Item 15.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
a. The following documents are filed as a part of this report:
(1) FINANCIAL STATEMENTS: The following financial statements of the Registrant and Report of Independent Registered Public Accounting Firm therein are filed as part of this Report on Form 10-K:
Page
Report of Farmer, Fuqua & Huff, P.C
Independent Registered Public Accounting Firm
Consolidated Balance Sheets 48-49
Consolidated Statements of Operations
Consolidated Statements of Changes in Stockholders' Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULES:
Schedule II - Valuation and Qualifying Accounts
Schedule III - Real Estate and Accumulated Depreciation
Other financial statement schedules have been omitted because the information required to be set forth therein is not applicable, is immaterial or is shown in the consolidated financial statements or notes thereto.
(b) The Index of Exhibits is included following the Financial Statement Schedules beginning at page 72 of this Report.
(c) The Index to Consolidated Financial Statements and Supplemental Schedules is included following the signatures, beginning at page 45 of this Report
(d) Supplemental Reserve Information (unaudited) is included in Note 18 to the Consolidated Financial Statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Shareholders of Spindletop Oil & Gas Co.
We have audited the accompanying consolidated balance sheets of Spindletop Oil & Gas Co. (A Texas Corporation) and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the years in the three-year period ended December 31, 2014. Spindletop Oil & Gas Co.’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Spindletop Oil & Gas Co. and subsidiaries as of December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.
We were not engaged to examine management’s assertion about the effectiveness of Spindletop Oil & Gas Co.’s internal control over financial reporting as of December 31, 2014 included in the accompanying management report on internal control over financial reporting and, accordingly, we do not express an opinion thereon.
Our audits were made for the purpose of forming an opinion on the basic consolidated financial statements taken as a whole. The schedules listed in the index of the consolidated financial statements are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly state, in all material respects, the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
/s/ Farmer, Fuqua & Huff, P.C.
Richardson, Texas
April 15, 2015
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND ORGANIZATION
Merger and Basis of Presentation
On July 13, 1990, Prairie States Energy Co., a Texas corporation, (the Company) merged with Spindletop Oil & Gas Co., a Utah corporation (the Acquired Company). The name of Prairie States Energy Co. was changed to Spindletop Oil & Gas Co., a Texas corporation at the time of the merger.
Organization and Nature of Operations
The Company was organized as a Texas corporation in September 1985, in connection with the Plan of Reorganization ("the Plan"), effective September 9, 1985, of Prairie States Exploration, Inc., ("Exploration"), a Colorado corporation, which had previously filed for Chapter 11 bankruptcy. In connection with the Plan, Exploration was merged into the Company, with the Company being the surviving corporation. After giving effect to a stock split, up to a total of 166,667 of the Company's common shares may be issued to Exploration's former shareholders. As of December 31, 2014, 122,436 shares have been issued to former shareholders in connection with the Plan.
Spindletop Oil & Gas Co. is engaged in the exploration, development and production of oil and natural gas; and through one of its subsidiaries, the gathering and marketing of natural gas.
The Company owns land along with a commercial office building which contains approximately 46,286 of rentable square feet, of which the Company occupies approximately 12,759 rentable square feet as its corporate office headquarters. The Company leases the remaining space in the building to non-related third party commercial tenants at prevailing market rates.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies consistently applied in the preparation of the accompanying financial statements follows:
FASB Accounting Standards Codification
The Company presents its financial statements in accordance with generally accepted accounting principles in the United States ("GAAP"). In June, 2009, the Financial Accounting Standards Board ("FASB") completed its accounting guidance codification project. The FASB Accounting Standards Codification ("ASC") became effective for the Company's financial statements issued subsequent to June 30, 2009 and is the single source of authoritative accounting principles recognized by the FASB to be applied to nongovernmental entities in the preparation of financial statements in conformity with GAAP. Accordingly, the Company refers to the ASC as the sole source of authoritative literature.
Consolidation
The consolidated financial statements include the accounts of Spindletop Oil & Gas Co. and its wholly owned subsidiaries, Prairie Pipeline Co. and Spindletop Drilling Company. All significant inter-company transactions and accounts have been eliminated.
Cash and Cash Equivalents
The Company considers all highly liquid instruments with a maturity of three months or less at time of original issuance to be cash equivalents.
Other Investments
Other short-term and long-term investments consist of certificates of deposit with maturities of more than three months. Carrying amounts approximate fair value.
Allowance for Doubtful Accounts
The Company provides an allowance for doubtful accounts equal to the estimated uncollectible portion of accounts receivable. This estimate is based on historical collection experience and a review of the current status of accounts receivable.
Oil and Gas Properties
The Company follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and natural gas reserves are capitalized and accounted for in cost centers, on a country-by-country basis. For each cost center, capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount (the cost center ceiling) equal to the sum of:
a) The present value of estimated future net revenues computed by applying current prices of oil and natural gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus
b) The cost of properties not being amortized; plus
c) The lower of cost or estimated fair market value of unproven properties included in the costs being amortized; less
d) Income tax effects related to differences between the book and tax basis of the properties.
If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling (as defined), the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts required to be written off will not be reinstated for any subsequent increase in the cost center ceiling. No impairment of oil and gas properties charge was recorded for 2014, 2013 or 2012.
Depreciation and amortization for each cost center are computed on a composite unit-of-production method, based on estimated proven reserves attributable to the respective cost center. All costs associated with oil and gas properties are currently included in the base for computation and amortization. Such costs include all acquisition, exploration, development costs and estimated future expenditures for proved undeveloped properties as well as estimated dismantlement and abandonment costs as calculated under the asset retirement obligation category, net of salvage value. All of the Company's oil and gas properties are located within the continental United States.
Gains and losses on sales of oil and gas properties are treated as adjustments of capitalized costs. Gains or losses on sales of property and equipment, other than oil and gas properties, are recognized as part of operations. Expenditures for renewals and improvements are capitalized, while expenditures for maintenance and repairs are charged to operations as incurred.
Property and Equipment
The Company, as operator, leases equipment to owners of oil and gas wells, on a month-to-month basis.
The Company, as operator, transports natural gas through its natural gas gathering systems, in exchange for a fee.
Depreciation is provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives (5 to 10 years for rental equipment and natural gas gathering systems, 4 to 5 years for other property and equipment). The straight-line method of depreciation is used for financial reporting purposes, while accelerated methods are used for tax purposes.
Real Estate Property
The Company owns land along with a two-story commercial office building which is situated thereon. The Company occupies a portion of the building as its primary corporate headquarters, and leases the remaining space in the building to non-related third party commercial tenants at prevailing market rates. The Company depreciates the commercial office using the straight-line method of depreciation for financial statement and income tax purposes.
Investments in Real Estate
All investments in real estate holdings are stated at cost or adjusted carrying value. ASC Topic 360, “Accounting for the Impairment or Disposal of Long-Lived Assets”, requires that a property be considered impaired if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the property. If impairment exists, an impairment loss is recognized by a charge against earnings equal to the amount by which the carrying amount of the property exceeds fair market value less cost to sell the property. If impairment of a property is recognized, the carrying amount of the property is reduced by the amount of the impairment, and a new cost for the property is established. Depreciation is provided over the properties estimated remaining useful life. There was no charge to earnings during 2014 due to impairment of real estate holdings.
Accounting for Asset Retirement Obligations
The Company adopted ASC Topic 410-20, "Accounting for Asset Retirement Obligations" on December 31, 2005. This statement requires the recording of a liability in the period in which an asset retirement obligation ("ARO") is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter, each quarter, this liability is accreted up to the final retirement cost. The determination of the ARO is based on an estimate of the future cost to plug and abandon our oil and gas wells. The actual costs could be higher or lower than current estimates.
The following table reflects the changes of the asset retirement obligations during the period ending December 31;
Revenue Recognition
The Company follows the “sales” (takes or cash) method of accounting for oil and natural gas revenues. Under this method, the Company recognizes revenues on oil and natural gas production as it is taken and delivered to the purchasers. The volumes sold may be more or less than the volumes the Company is entitled to take based on our ownership in the property. These differences result in a condition known as a production imbalance. Our crude oil and natural gas imbalances are insignificant.
Income Taxes
In June, 2006, an interpretation of ASC Topic 740-10, “Accounting for Uncertainty in Income Taxes” was issued. The interpretation creates a single model to address accounting for uncertainty in tax positions. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition of certain tax positions. Federal and state tax authorities generally have the right to examine and audit the previous three years of tax returns filed.
The Company adopted the provisions of the interpretation of ASC Topic 740-10 effective January 1, 2007. The adoption of this accounting principle did not have an effect on the Company’s consolidated financial statements at, and for the three years ended December 31, 2014.
The Company accounts for income taxes pursuant to ASC Topic 740-10 "Accounting for Income Taxes" , which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities, using enacted tax rates in effect in the years in which the differences are expected to reverse. The temporary differences primarily relate to depreciation, depletion and intangible drilling costs.
Use of Estimates
The preparation of financial statements in conformity with U. S. Generally Accepted Accounting Principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Share-Based Payments
Effective January 1, 2006, the Company adopted ASC Topic 718-10, “Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized in the income statement over the requisite service period. The amount of the compensation cost is to be measured based on the grant-date fair value of the instrument issued. ASC Topic 718-10 is effective for awards granted or modified after the date of adoption and for awards granted prior to that date that have not vested. ASC Topic 718-10 does not materially change the Company's existing accounting practices or the amount of share-based compensation recognized in earnings.
Recently Issued Accounting Pronouncements
The FASB issued Accounting Standards Update No 2013-02 “Comprehensive Income (Topic 220); Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The objective of this Update is to improve the reporting of reclassification out of accumulated other comprehensive income. The amendments in this Update apply to all entities that issue financial statements that are presented in conformity with U.S. GAAP and that report items of other comprehensive income. The amendments are effective for reporting periods beginning after December 15, 2013. The Company has adopted this amendment as of the effective date; however the adoption of this amendment will not have a material impact on the consolidated financial statements of the Company.
Currently, there are no other new accounting pronouncements that were issued to be effective in 2014 or subsequent thereto that would have a material impact on the Company’s financial reporting.
Subsequent Events
The Company has evaluated subsequent events through the issuance date of April 15, 2015.
3. ACCOUNTS RECEIVABLE
Accrued receivables are receivables from purchasers of oil and gas. These revenues are booked from check stub detail after receipt of the check for sales of oil and natural gas products. These payments are for sales of oil and natural gas produced in the reporting period, but for which payment has not yet been received until after the closing date of the reporting period. Therefore these sales are accrued as receivables as of the balance sheet date. Revenues for oil and natural gas production that has been sold but for which payment has not yet been received is accrued in the period sold.
4. ACCOUNTS PAYABLE
5. NOTES PAYABLE
Effective December 27, 2013, the Company prepaid the remaining principal balance plus accrued interest on its note payable to a bank for the commercial office building. The note was paid in full.
6. RELATED PARTY TRANSACTIONS
On October 1, 2008, Giant entered into an Administrative Services Agreement with the Company whereby Giant agreed to pay the Company $250 per month for the Company providing administrative services to Giant. The Company also entered into a management services agreement with M-R Oilfield Services, LP (“MRO”), whereby MRO makes monthly payments in the amount of $1,000 to the Company in exchange for the Company providing administrative services to MRO. On October 1, 2008, the Company entered into a similar agreement with Giant NRG, LP (“NRG”), a limited partnership with Chris Mazzini and Michelle Mazzini as limited partners. Under this agreement NRG pays a monthly fee of $2,500 to the Company in exchange for the Company providing certain administrative services to NRG. The Company has entered into a similar arrangement with Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly charge of $250 in exchange for the Company providing administrative services to Peveler. Chris and Michelle Mazzini are the owners of Peveler Pipeline, LP, a limited partnership which owns a pipeline gathering system servicing wells owned by Giant, another related entity, described elsewhere in this report. The Company entered into a similar agreement with M-R Ventures, LLC (“MRV”), a limited liability company that operates some wells in Michigan, and that is owned by Chris and Michelle Mazzini. Pursuant to this agreement, MRV pays the Company a monthly fee in the amount of $500 for certain administrative services that the Company provides to MRV. The Company entered into a similar agreement with Reserve Royalty Company (“Reserve”) a sole proprietorship that holds some royalty interests owned by Chris and Michelle Mazzini. Pursuant to this agreement, Reserve pays the Company a monthly fee in the amount $350 for certain administrative services that the Company provides to Reserve.
The long-term debt, which was secured by the commercial office building, was also guaranteed individually by Chris G. Mazzini and Michelle H. Mazzini, related parties. Effective December 27, 2013, the Company prepaid the remaining principal balance plus accrued interest and the note was paid in full.
7. COMMON STOCK
Effective January 1, 2006, the Company adopted ASC Topic 718-10, "Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized in the income statement over the requisite service period. The amount of the compensation cost is to be measured based on the grant date fair value of the instrument issued. ASC Topic 718-10 is effective for awards granted or modified after the date of adoption and for awards granted prior to that date that have not vested. ASC Topic 718-10 does not materially change the Company's existing accounting practices or the amount of share-based compensation recognized in earnings.
During the three year period ending December 31, 2014, the Company did not issue any compensation related to share-based payments.
The Company has not approved nor authorized any standing repurchase program for its common stock.
During the fourth quarter of the fiscal year ended December 31, 2012, the Company made the following repurchases of its common stock:
Effective October 30, 2012, the Company repurchased 700,000 shares of its common stock for a purchase price of $1,491,000 or $2.13 per share.
On December 18, 2012, the Company repurchased 24,534 shares of its common stock for a purchase price of $36,801 or $1.50 per share.
The Company made no repurchases of its common stock during 2013 or 2014.
The repurchased shares are held as Treasury Stock.
8. INCOME TAXES
The Company accounts for income taxes pursuant to ASC Topic 740-10, "Accounting for Income Taxes". ASC Topic 740-10 utilizes the liability method of computing deferred income taxes.
In connection with the Plan discussed in Note 1, the Company agreed to pay, in cash, to Exploration's unsecured creditors, as defined, one-half of the future reductions of Federal income taxes which were directly related to any allowed carryovers of Exploration's net operating losses and investment tax credits. Such payments are to be made on a pro-rata basis. Amounts incurred under this agreement, which are considered contingent consideration, totaled $ -0-, $ -0-, and $ -0- in 2014, 2013 and 2012, respectively. As of December 31, 2014 the Company has not received a ruling from the Internal Revenue Service concerning the net operating loss and investment credit carryovers. Until the tax savings which result from the utilization of these carry-forwards is assured, the Company will not pay to Exploration's unsecured creditors any of the tax savings benefit. As of December 31, 2014, the Company owes $97,000 to Exploration's unsecured creditors.
In calculating tax savings benefits described above, consideration was given to the alternative minimum tax, where applicable, and the tax effects of temporary differences, as shown below:
Income tax differed from the amounts computed by applying an effective United States federal income tax rate of 34% to pretax income in 2014, 2013 and 2012 as a result of the following:
Deferred income taxes reflect the effects of temporary differences between the tax bases of assets and liabilities and the reported amounts of those assets and liabilities for financial reporting purposes. Deferred income taxes also reflect the value of investment tax credits and an offsetting valuation allowance. The Company's total deferred tax assets and corresponding valuation allowance at December 31, 2014 and 2013 consisted of the following:
9. CASH FLOW INFORMATION
The Company does not consider any of its assets, other than cash and certificates of deposit shown as cash on the balance sheet, to meet the definition of a cash equivalent.
10. EARNINGS PER SHARE
Earnings per share ("EPS") are calculated in accordance with ASC Topic 260-10, "Earnings per Share", which was adopted in 1997 for all years presented. Basic EPS is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding during the period. The adoption of ASC Topic 260-10 had no effect on previously reported EPS. Diluted EPS is computed based on the weighted number of shares outstanding, plus the additional common shares that would have been issued had the options outstanding been exercised.
11. CONCENTRATIONS OF CREDIT RISK
Subsequent to December 31, 2012, FDIC Deposit Insurance coverage changed. As scheduled, the unlimited insurance coverage for noninterest-bearing transaction accounts provided under the Dodd-Frank Wall Street Reform and Consumer Protection Act expired on December 31, 2012. Deposits held in non-interest-bearing transaction accounts are now aggregated with any interest-bearing deposits the owner may hold in the same ownership category, and the combined total insured up to at least $250,000.
Beginning January 1, 2013, noninterest-bearing transaction accounts will no longer be insured separately from depositors’ other accounts at the same institution. Instead, noninterest-bearing transaction accounts will be added to any of a depositor’s other accounts in the applicable ownership category, and the aggregate balance insured up to at least the Standard Minimum Deposit Insurance Amount (SMDIA) of $250,000, per depositor, at each separately chartered institution.
As of December 31, 2014 the Company had approximately $11,081,000 in checking and money market accounts at one bank, and approximately $3,320,000 in a second bank. The Company also had approximately $2,981,000, including $400,000 of short-term certificates of deposit and $1,200,000 of long-term certificates of deposit invested at five other banking institutions. Cash amounts on deposit at these institutions exceeded current per account FDIC protection limits by approximately $13,852,000.
Most of the Company's business activity is located in Texas. Accounts receivable as of December 31, 2014 and 2013 are due from both individual and institutional owners of joint interests in oil and gas wells as well as purchasers of oil and natural gas. A portion of the Company's ability to collect these receivables is dependent upon revenues generated from sales of oil and natural gas produced by the related wells.
12. FINANCIAL INSTRUMENTS
The estimated fair value of the Company's financial instruments at December 31, 2014 and 2013 follows:
The fair value amounts for each of the financial instruments listed above approximate carrying amounts due to the short maturities of these instruments.
13. COMMITMENTS AND CONTINGENCIES
In connection with the Plan of Reorganization discussed in Note 1, the Company agreed to pay, in cash, to Exploration's unsecured creditors, as defined, one-half of the future reduction of Federal income taxes which were directly related to any allowed carryovers of Exploration's net operating losses and investment tax credits existing at the time of the reorganization.
The Company's oil and gas exploration and production activities are subject to Federal, State and environmental quality and pollution control laws and regulations. Such regulations restrict emission and discharge of wastes from wells, may require permits for the drilling of wells, prescribe the spacing of wells and rate of production, and require prevention and clean-up of pollution.
Although the Company has not in the past incurred substantial costs in complying with such laws and regulations, future environmental restrictions or requirements may materially increase the Company's capital expenditures, reduce earnings, and delay or prohibit certain activities.
At December 31, 2014 the Company has acquired bonds and letters of credit issued in favor of various state regulatory agencies as mandated by state law in order to comply with financial assurance regulations required to perform oil and gas operations within the various state jurisdictions.
The Company has seven, $5,000 single-well bonds totaling $35,000 and one $10,000 single well bond with an insurance company, for wells the Company operates in Alabama. The $5,000 bonds are written for a three year period and the $10,000 bond is written for a one year period.
The Company has 10 letters of credit from a bank issued for the benefit of various state regulatory agencies in Texas, New Mexico, Oklahoma, and Louisiana, ranging in amounts from $10,000 to $50,000 and totaling $298,000. These letters of credit have expiration dates that range from January 31, 2015 through March 31, 2016 and are fully secured by funds on deposit with the bank in business money market accounts.
14. ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION
Certain information about the Company's operations for the years ended December 31, 2014, 2013 and 2012 follows.
Sale of Oil & Gas Properties
In December, 2012, the Company sold its working interest effective October 1, 2012, in 29 non-operated properties located in Palo Pinto, Wise, Jack, and Parker Counties, Texas to the operator of the wells for a gross sales price of $165,000.
Dependence on Customers
The following is a summary of significant purchasers / operators (listed by percent of total oil and natural gas sales) from oil and natural gas produced by the Company for the three-year period ended December 31, 2014:
Oil and natural gas is sold to approximately 123 different purchasers under market sensitive, short-term contracts computed on a month to month basis.
Except as set forth above, there are no other customers of the Company that individually accounted for more than two percent of the Company's oil and gas revenues during the three years ended
December 31, 2014.
The Company currently has no hedged contracts.
Certain revenues, costs and expenses related to the Company's oil and gas operations are as follows:
15. BUSINESS SEGMENTS
The Company's three business segments are (1) oil and gas exploration, acquisition, production and operations, (2) transportation and compression of natural gas, and (3) commercial real estate investment. Management has chosen to organize the Company into the three segments based on the products or services provided. The following is a summary of selected information for these segments for the
three-year period ended December 31, 2014:
Note (1): All reported revenues are from external customers.
Note (2): Corporate and other includes general and administrative expenses,
other non-operating income and expense and income taxes.
Note (3): Corporate and other includes cash, accounts and notes receivable,
inventory, other property and equipment and intangible assets.
16. SUPPLEMENTARY INCOME STATEMENT INFORMATION
The following items were charged directly to expense:
17. QUARTERLY DATA (UNAUDITED)
The table below reflects selected quarterly information for the years ended December 31, 2014, 2013 and 2012.
18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The Company’s net proved oil and natural gas reserves as of December 31, 2014, 2013, and 2012 have been estimated by Company personnel.
All estimates are in accordance generally accepted petroleum engineering and evaluation principles and definitions and with guidelines established by the Securities and Exchange Commission. All of the Company’s reserves are located in the United States of America and accounted for under one cost center.
Our policies and practices regarding internal control over the estimating of reserves are structured to objectively and accurately estimate our oil and natural gas reserve quantities and present values in compliance with the U.S. Securities and Exchange Commission (“SEC”) regulations and accounting principles generally accepted in the United States of America. We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with the accounting and financial departments to insure the integrity, accuracy and timeliness of data used in the estimation process. The data used in our reserve estimation process is based on historical results for production, oil and natural gas prices received, lease operating expenses and development costs incurred, ownership interest and other required data. Historical oil and natural gas prices, lease operating expenses, and ownership interests are provided by and verified by the Company’s accounting department.
The Petroleum Engineer responsible for the supervision and preparation of the Company’s internally generated reserve report has a Bachelor of Science degree in Petroleum Engineering from a major university and has experience in preparing economic evaluations and reserve estimates. He meets the requirements regarding qualifications, objectivity and confidentiality set forth in the Standards Pertaining to the Engineering and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
The Company has established a written internal control procedure to verify that the data entered into our engineering evaluation software is complete and correct. These internal control procedures establish the source of the data both internally and externally, the personnel that will collect the data and testing of the data collected to ensure its accuracy.
The following reserve estimates were based on existing economic and operating conditions. Oil and natural gas prices for 2014, 2013, and 2012 were calculated using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of each year. Operating costs, production and ad valorem taxes and future development costs were based on current costs with no escalation.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of the Company's oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves.
Changes in Estimated Quantities of Proved Oil and Gas Reserves (Unaudited):
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (Unaudited)
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves ("Standardized Measures") does not purport to present the fair market value of a company's oil and gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.
Reserve estimates were prepared in accordance with standard Security and Exchange Commission guidelines. The future net cash flow for 2014, 2013, and 2012, was computed using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of the year. Lease operating costs, compression, dehydration, transportation, ad valorem taxes, severance taxes, and federal income taxes were deducted. Costs and prices were held constant and were not escalated over the life of the properties. No deduction has been made for interest, or general corporate overhead. The annual discount of estimated future cash flows is defined, for use herein, as future cash flows discounted at 10% per year, over the expected period of realization.
Proved Developed Reserves were calculated based on Decline Curve Analysis on 76 operated wells and 71 non-operated wells. Materially insignificant operated and non-operated wells were excluded from the reserve estimate.
The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is reasonably possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, that the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of the oil and natural gas properties, or any combination of the above may be increased or reduced in the near term. If reduced, the carrying amount of capitalized oil and gas properties may be reduced materially in the near term.
Changes in the standardized measure of discounted future net cash flows:
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012
Exhibit 21
SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES
Subsidiaries of the Registrant
Spindletop Drilling Company, incorporated September 5, 1975, under the laws of the State of Texas, is a wholly owned subsidiary of the Registrant.
Prairie Pipeline Co. incorporated June 22, 1983, under the laws of the State of Texas, is a wholly owned subsidiary of Registrant.
Exhibit 31.1
CERTIFICATIONS
I, Chris G. Mazzini, certify that:
1.	I have reviewed this report on Form 10-K of Spindletop Oil & Gas Co.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13-15(e) and 15d-15e) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:
(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the controls and procedures as of the end of the period covered by this report based on such evaluation; and
(d)disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's Board of directors (or persons performing the equivalent functions):
(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls.
Exhibit 31.2
CERTIFICATIONS
I, Robert E. Corbin, certify that:
1.	I have reviewed this report on Form 10-K of Spindletop Oil & Gas Co.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13-15(e) and 15d-15e) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:
(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the controls and procedures as of the end of the period covered by this report based on such evaluation; and
(d)disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's Board of directors (or persons performing the equivalent functions):
(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls.
Exhibit 32
Certification Pursuant to 18 U.S.C. Section 1350
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the Annual Report of Spindletop Oil & Gas Co. (the “Company”), on Form 10-K for the year ended December 31, 2014 as filed with the Securities Exchange Commission on the date hereof (the “Report”), the undersigned Principal Executive Officer and Principal Financial and Accounting Officer of the Company, do hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.
Date: April 15, 2015
By:/s/ Chris G. Mazzini
Chris G. Mazzini
President, Principal Executive Officer
By:/s/ Robert E. Corbin
Robert E. Corbin
Controller, Principal Financial and
Accounting Officer