The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K.
Liquidity and Capital Resources and Commitments
Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings and issuance of common stock. Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to secure our revolving line of credit. We do not have any delivery commitments to provide a fixed and determinable quantity of our oil and gas under any existing contract or agreement. Our long term strategy is on increasing profit margins while concentrating on obtaining reserves with low cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interest, non-operated properties in areas with significant development potential.
We had working capital of
For the year ending
March 31, 2014, cash flow from operations was $1,812,501, a 122% increase when compared to the corresponding period of fiscal 2013. Net cash of $1,187,090was used for additions to oil and gas properties and equipment; net cash of $525,000was used to reduce the balance on the line of credit; and cash of $54,281was used for settlement of derivatives. Accordingly, net cash decreased $10,324. 26 -------------------------------------------------------------------------------- At March 31, 2014, we reported estimated proved undeveloped reserves ("PUDs") of 3.4 bcfe, which accounted for 37% of our total estimated proved oil and gas reserves. This figure primarily consists of a projected 54 new wells, three (3) of which we operate, and one new zone behind pipe from a currently producing wellbore that we also operate. We project two (2) operated wells to be drilled in fiscal 2015 with the one remaining in fiscal 2016. Regarding the remaining 51 PUD locations operated by others, five (5) wells currently are being drilled and two (2) locations currently are being prepared to drill with plans for ten (10) wells to follow in 2015, 30 wells in 2016 and four (4) wells in 2017. On March 31, 2014, Mexco acquired for $450,000, a package of non-operated producing properties primarily consisting of oil wells located in Webster Parish, Louisiana; Eddy County, New Mexico; Billings County, North Dakota; and Nolanand SmithCounties, Texas. This purchase, effective March 1, 2014, includes working interests ranging from .13% to 27.5% (net revenue interests of .11% to 24.06%) adding estimated net proved reserves of approximately 35,000 barrels of oil equivalent at a cost of $12.68per barrel.
August 13, 2013, Mexco assigned Pioneer Natural Resources Company a three year term leasehold interest in 417.33 net acres (837.33 gross acres) in Upton County, Texasin return for payment to Mexco of $1,500per acre totaling $625,995. Mexco retained a 1% royalty. This interest has potential for oil production from the Horizontal Wolfcamp trend of the Permian Basinin West Texas. In August 2013, a joint venture in which we are a working interest partner entered into an agreement for the assignment of a three year term leasehold interest for the deeper rights to the Wolfcamp formation in acreage in Reagan County, Texas. We received $330,958in cash and retained minor royalties as payment for our share of the leasehold acreage. A joint venture in which we are a working interest partner entered into a joint development agreement to develop the Wolfcamp B formation using horizontal drilling and multi-stage fracture stimulation on a 1,125-acre tract in Reagan County, Texas. There are seven (7) prospective drill sites on this acreage planned to be drilled during calendar year 2014. Our share of the costs to drill, test and complete the first two wells through March 31, 2014and purchase additional working interests for our now approximate 1.45% working interest (1.25% net revenue interest) was approximately $244,000. Subsequently, a third well was drilled at an additional cost of $124,000. We participated in the drilling of three (3) horizontal wells in the Wolfcamp formation of the Lin Field of Reagan County, Texas. All three (3) of these wells have been completed and are currently producing and undergoing fracture stimulation. The unit, operated by EOG Resources, Inc., contains approximately 500 acres. Mexco's working interest in these wells is .8086% (.6064% net revenue interest). Our share of the costs to drill, complete and fracture these wells through March 31, 2014was approximately $149,000. Subsequently, in April 2014, EOG announced plans to drill a fourth well in this unit. We participated in the drilling of eight (8) horizontal wells in the Penn Detrital formation of the F A Hogg Field of Winkler County, Texas. Six (6) of these wells have been completed and are currently producing with two (2) wells undergoing completion procedures. The eight units, seven operated by OGX Operating, LLCand one operated by Petro-Hunt LLC, contain approximately 2,600 acres. Mexco's working interests in these wells range from .2919% to .4167% (.2275% to .3125% net revenue interest). Our share of the costs to drill and complete these wells through March 31, 2014was approximately $95,000. We participated in the drilling of three (3) development wells in the Wolfcamp formation of the Clyde-Reynolds Field of Glasscock County, Texas. All three (3) of these wells have been drilled and are currently undergoing completion procedures. There are two (2) units, one operated by McClure Oil Company, Inc.and one operated by Nadeland Gussman Permian LLC, which contain in total approximately 1,000 acres. Mexco's working interests in these wells range from .7% to 1% (.525% to .75% net revenue interest). Our share of the costs to drill and complete these wells through March 31, 2014was approximately $24,000. 27 -------------------------------------------------------------------------------- We participated in the drilling of two (2) wells to an approximate depth of 5,000 feet in the Grayburg and San Andres formations of the Fuhrman-Mascho Field of Andrews County, Texas. One of these wells has been completed and is currently undergoing completion procedures. The unit, operated by Cone & Petree Oil & Gas Exploration, Inc., contains 160 gross acres and a total of ten (10) wells - four (4) producing oil from the San Andres formation and five (5) producing oil from the Grayburg and San Andres formations. Our share of the costs for our approximate 16.2% working interest (11.66% net revenue interest) of these last two (2) wells through March 31, 2014was approximately $214,000. This property contains an additional six (6) potential drill sites in the Grayburg and San Andres formations with three (3) planned to be drilled in 2014. A joint venture in which we are a working interest partner drilled four (4) development wells in the Atoka/Bend through Spraberry formations on 640 acres in Reagan County, Texas. As of March 31, 2014, three (3) of these wells have been completed and are currently producing. The fourth well began producing subsequently in April 2014. Our share of the costs to drill and complete these wells through March 31, 2014for our approximate .69% working interest (.52% net revenue interest) was approximately $75,000. On March 31, 2014but effective March 1, we purchased for $74,000, a 1.45% net royalty interest in 159.4 gross acres in Howard County, Texas. This acreage currently has one vertical well with a total depth of approximately 10,300 feet operated by CrownQuest Operating, LLC. This well began producing from the Spraberry trend area in July 2013. This acreage is free of expenses to Mexco for drilling and operations and has potential for further development. Also on March 31, 2014but effective March 1, we purchased for $200,000long-lived non-operated producing properties consisting of 58 oil wells operated by Cross Timbers Energy, LLC, a joint venture of Exxon Mobil Corporation and MorningStar Partners, LPin Hockley County, Texasand 22 oil wells operated by Four C Oil & Gas Corporationin Pecos County, Texas. This acquisition includes working interests of, respectively, .42% and .67% (net revenue interests of .31% and .50%). New MexicoWe participated in the drilling of nine (9) horizontal wells in the Bone Springsformation of Lea County, New Mexico. Five (5) of these wells are operated by COG Operating, LLC, five (5) are operated by Cimarex Energy and one is operated by Manzano, LLC. All of these wells have been completed and are currently producing. In January 2014, Cimarex announced plans to drill two (2) additional wells in this formation. Mexco's working interests in these wells range from .047% to .25% (.035% to .2125% net revenue interest). Our share of the costs to drill and complete these wells through March 31, 2014was approximately $70,000. A joint venture in which we are a working interest partner entered into a joint development agreement to develop the Avalon Shaleportion of the Bone Spring formation using horizontal drilling and multi-stage fracture stimulation on a 640-acre tract in Lea County, New Mexico. There are twelve prospective drill sites on this acreage. Our share of the costs to drill and complete the first well through March 2014for our approximate .56% working interest (.42% net revenue interest) was approximately $32,000. We have been scheduled to participate in twelve (12) infill wells in the Yeso/Paddock formations of the Dodd-Federal Unit in the Grayburg San Andres Jackson Field of Eddy County, New Mexico. Eight (8) vertical and three (3) horizontal wells were drilled during the first six months of fiscal 2014 to a total vertical depth of approximately 5,000 feet. The unit, operated by Concho Resources, Inc., currently contains approximately 184 producing wells. Mexco's working interest in this unit is .1848% (.14% net revenue interest). Our share of the costs to drill and complete these eleven wells through March 31, 2014was approximately $39,000. OklahomaWe participated in the drilling of three (3) horizontal wells in a 640 acre unit in the Cottage Groveformation of Ellis County, Oklahoma. All three (3) of these wells, operated by Mewbourne Oil Company, have been completed and are currently producing. Mexco's working interest in this unit is 1.2% (.9878% net revenue interest). Our share of the costs to drill and complete these wells through March 2014was approximately $121,000. 28 --------------------------------------------------------------------------------
We participated in the drilling of a horizontal infill well on a 1,280-acre unit in the Bakken and Three Forks formations of the Catwalk Creek Field of
Williams County, North Dakota. This well, operated by Continental Resources, Inc. has been completed and is currently producing. Mexco's working interest in this unit is .078% (.068% net revenue interest). As of March 31, 2014, our share of the costs associated with this well was approximately $6,100. In March 2014, we purchased for $57,000, a royalty interest in 320 gross acres (15 net mineral acres) subject to a 3/16ths royalty lease in the Bakken Shaleformation of Billings County, North Dakota. This acreage currently contains one newly drilled horizontal well operated by Continental Resources, Inc. This well produced on a 18/64" choke flow test on March 18, 2014at a rate of 413 bbls of oil per day, 396 mcf of natural gas per day with a flowing tubing pressure of 950 pounds per square inch and 768 barrels of water per day. All of this acreage is free of expenses to Mexco for drilling, development and operations. We are participating in other projects and are reviewing projects in which we may participate. The cost of such projects would be funded, to the extent possible, from existing cash balances and cash flow from operations. The remainder may be funded through borrowings on the credit facility and, if appropriate, sales of our common stock. See Note 5 of Notes to Consolidated Financial Statements for a description of our revolving credit agreement with Bank of America, N.A. Crude oil and natural gas prices have fluctuated significantly in recent years. Lower product prices reduce our cash flow from operations and diminish the present value of our oil and gas reserves. Lower product prices also offer us less incentive to assume the drilling risks that are inherent in our business. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example in the last twelve months, the West Texas Intermediate ("WTI") posted price for crude oil has ranged from a low of $83.25per bbl in April 2013to a high of $107.00per bbl in September 2013. The Henry Hub Spot Market Price ("Henry Hub") for natural gas has ranged from a low of $3.27per MMBtu in August 2013to a high of $7.98per MMBtu in March 2014. On March 31, 2014the WTI posted price for crude oil was $97.75per bbl and the Henry Hub spot price for natural gas was $4.48per MMBtu. Management is of the opinion that cash flow from operations and funds available from financing will be sufficient to provide adequate liquidity for the next fiscal year.
Results of Operations
Fiscal 2014 Compared to Fiscal 2013
We had a net income of
Oil and gas sales. Revenue from oil and gas sales was
$3,994,295for the year ended March 31, 2014, a 30% increase from $3,063,707for the year ended March 31, 2013. This resulted from an increase in oil production and an increase in oil and gas prices partially offset by a decrease in gas production. The following table sets forth our oil and gas revenues, production quantities and average prices received during the fiscal years ended March 31: 2014 2013 % Difference Oil: Revenue $ 2,591,619 $ 1,961,76632.1 % Volume (bbls) 27,186 23,260 16.9 % Average Price (per bbl) (a) $ 95.33 $ 84.3413.0 % Gas: Revenue $ 1,402,676 $ 1,101,94127.3 Volume (mcf) 361,652 401,077 (9.8 %) Average Price (per mcf) $ 3.88 $ 2.7541.1 %
(a) After giving effect to our derivative instruments, the average sales price
per Bbl of oil was
price swap agreement on our oil production for the year ended
29 -------------------------------------------------------------------------------- Production and exploration. Production costs were
$1,231,814in fiscal 2014, a 14% increase from $1,082,043in fiscal 2013. This was primarily the result of an increase in taxes related to an increase in sales, and fiscal 2014 includes twelve months of costs from the TBO wells compared to 3 months in fiscal 2013. Depreciation, depletion and amortization. Depreciation, depletion and amortization ("DD&A") expense was $1,151,482in fiscal 2014, a 5% increase from $1,100,425in fiscal 2013. This was due to an increase in oil production and a decrease in gas reserves partially offset by a decrease in gas production and an increase in oil reserves. General and administrative expenses. General and administrative expenses were $1,136,939for the year ended March 31, 2014, an 11% increase from $1,028,846for the year ended March 31, 2013. This was primarily due to an increase in engineering services, insurance, salaries and stock option compensation expense.
Interest expense. Interest expense was
Income taxes. There was an income tax expense of
$11,750in fiscal 2014 compared to an income tax benefit of $31,504in fiscal 2013. The effective tax rate for fiscal 2014 was 4% compared to (15%) for fiscal 2013. Derivatives. Derivative losses of $99,262were recorded during the year ended March 31, 2014. This amount reflects $54,281of realized losses and $44,981of unrealized losses resulting from our oil swap agreement.
Fiscal 2013 Compared to Fiscal 2012
There was a net loss of
Oil and gas sales. Revenue from oil and gas sales was
$3,063,707for the year ended March 31, 2013, a 5% decrease from $3,223,659for the year ended March 31, 2012. This resulted from an increase in oil and gas production partially offset by a decrease in oil and gas prices. The following table sets forth our oil and gas revenues, production quantities and average prices received during the fiscal years ended March 31: 2013 2012 % Difference
$ 1,961,766 $ 1,810,4598.4 % Volume (bbls) 23,260 19,442 19.7 % Average Price (per bbl) $ 84.34 $ 93.12(9.4 %)
$ 1,101,941 $ 1,413,200(22.0 %) Volume (mcf) 401,077 395,649 1.4 % Average Price (per mcf) $ 2.75 $ 3.57(23.0 %)
Production and exploration. Production costs were
Depreciation, depletion and amortization. Depreciation, depletion and amortization ("DD&A") expense was
$1,100,425in fiscal 2013, a 10% increase from $996,205in fiscal 2012. This was due to an increase in oil and gas production and an increase in the full cost pool amortization base partially offset by a decrease in oil and gas reserves. General and administrative expenses. General and administrative expenses were $1,028,846for the year ended March 31, 2013, an 8% increase from $950,690for the year ended March 31, 2012. This was primarily due to an increase in insurance, salaries and stock option compensation expense. 30 --------------------------------------------------------------------------------
Interest expense. Interest expense was
Income taxes. There was an income tax benefit of
We have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes our future payments we are obligated to make based on agreements in place as of
Payments due in: Total less than 1 year 1 - 3 years 3 years Contractual obligations: Secured bank line of credit (1)
$ 2,425,000$ - $ 2,425,000$ - Leases (2) $ 38,040$ 19,020 $ 19,020$ -
(1) These amounts represent the balances outstanding under the bank line of
credit. These repayments assume that interest will be paid on a monthly basis, no additional funds will be drawn and does not include estimated interest of
$64,335less than 1 year and $42,8901-3 years.
(2) The total obligation for the remainder of the leases is
portion of the shared office space.
Alternative Capital Resources
Although we have primarily used cash from operating activities and funding from the line of credit as our primary capital resources, we have in the past, and could in the future, use alternative capital resources. These could include joint ventures, carried working interests and the sale of assets and/or issuances of common stock through a private placement or public offering of our common stock. Other Matters
Critical Accounting Policies and Estimates
In preparing financial statements, management makes informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, fair value and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.
Full Cost Method of Accounting for Crude Oil and Natural Gas Activities.
SECRegulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation ("ARO") when incurred. 31 -------------------------------------------------------------------------------- Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of crude oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the "full cost" pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher DD&A rate on our crude oil and natural gas properties. At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us more susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. Our crude oil and natural gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from the full cost method of accounting. Ceiling Test. Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling limitation write-down." This charge does not impact cash flow from operating activities, but does reduce our stockholders' equity and reported earnings. The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period. Estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SECguidelines by an independent engineering firm based in part on data provided by us. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgment of the persons preparing the estimate. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. It should not be assumed that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SECrequirements, the cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production using the average price over the prior 12-month period. The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost projects. 32 -------------------------------------------------------------------------------- Use of Estimates. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining year end proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of our oil and natural gas reserves, which is used to compute DD&A and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results. Excluded Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the DD&A pool). Impairments transferred to the DD&A pool increase the DD&A rate. Revenue Recognition. We recognize crude oil and natural gas revenue from our interest in producing wells as crude oil and natural gas is sold from those wells, net of royalties. We utilize the sales method to account for gas production volume imbalances. Under this method, income is recorded based on our net revenue interest in production taken for delivery. Asset Retirement Obligations. The estimated costs of plugging, restoration and removal of facilities are accrued. The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated by the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in the full cost amortization base and amortize these costs as a component of our depletion expense. Derivatives. The Company uses price swap contracts to reduce price volatility associated with certain of its oil sales. All derivative financial instruments are recorded at fair value on the balance sheet as either assets or liabilities. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in the Consolidated Statements of Operations under the caption "Loss on derivative instruments." Gas Balancing. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when our excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where Mexco has taken less than its ownership share of gas production (under produced). Stock-based Compensation. We use the Binomial option pricing model to estimate the fair value of stock based compensation expenses at grant date. This expense is recognized as compensation expense in our financial statements over the vesting period. We recognize the fair value of stock based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period. Accounts Receivable. Our accounts receivable include trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer's financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectability of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on our previous loss history. 33
Income Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively. Other Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years. Recent Accounting Pronouncements. In
May 2014, the Financial Accounting Standards Board("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, Topic 606: Revenue from Contracts with Customers. ASU No. 2014-09 is effective for Mexco as of April 1, 2017. Management is evaluating the effect, if any this pronouncement will have on our consolidated financial statements.