MEXCO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Nature of Operations
Mexco Energy Corporation (a Colorado corporation) and its wholly owned subsidiaries, Forman Energy Corporation (a New York corporation), Southwest Texas Disposal Corporation (a Texas corporation) and TBO Oil & Gas, LLC (a Texas limited liability company) (collectively, the “Company”) are engaged in the exploration, development and production of natural gas, crude oil, condensate and natural gas liquids (“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas; however, the Company owns producing properties and undeveloped acreage in twelve states. Although most of the Company’s oil and gas interests are operated by others, the Company operates several properties in which it owns an interest.
On December 31, 2012, Mexco Energy Corporation acquired all of the outstanding ownership interests of TBO Oil & Gas, LLC, a Texas limited liability company which owns non-operated working interests in over 280 wells producing primarily oil.
2. Basis of Presentation and Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned subsidiaries. All significant intercompany balances and transactions associated with the consolidated operations have been eliminated.
Estimates and Assumptions. 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 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 the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.
Interim Financial Statements. In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments (consisting only of normal recurring accruals) necessary to present fairly the financial position of the Company as of December 31, 2012, and the results of its operations and cash flows for the interim periods ended December 31, 2012 and 2011. The financial statements as of December 31, 2012 and for the three and nine month periods ended December 31, 2012 and 2011 are unaudited. The consolidated balance sheet as of March 31, 2012 was derived from the audited balance sheet filed in the Company’s 2012 annual report on Form 10-K filed with the Securities and Exchange Commission (“SEC”). The results of operations for the periods presented are not necessarily indicative of the results to be expected for a full year. The accounting policies followed by the Company are set forth in more detail in Note 2 of the “Notes to Consolidated Financial Statements” in the Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the SEC. However, the disclosures herein are adequate to make the information presented not misleading. It is suggested that these financial statements be read in conjunction with the financial statements and notes thereto included in the Form 10-K.
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 exceeds our estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced). The Company does not have any significant gas imbalances.
Recent Accounting Pronouncements. There were no accounting standards and interpretations issued during the reporting period which were applicable to the Company.
3. Business Combinations and Property Acquisitions
On December 31, 2012, the Company purchased all of the outstanding ownership interests of TBO Oil & Gas, LLC (“TBO”), a Texas limited liability company which owns non-operated working interests in approximately 280 wells producing primarily oil, expanding the Company’s revenues. The cash purchase price of $1,150,000 was funded from our $4.9 million bank credit facility. The Company’s results of operations for the three and nine months periods for 2012 and 2011 do not include any revenues or costs from TBO.
The purchase price was allocated to the assets acquired and liabilities assumed at estimated fair values as follows:
|
Proved oil and gas properties
|
|
$ |
1,204,760 |
|
|
Accounts receivable
|
|
|
72,346 |
|
|
Total assets acquired
|
|
|
1,277,106 |
|
| |
|
|
|
|
|
Accounts payable
|
|
|
(46,346 |
) |
|
Asset retirement obligations assumed
|
|
|
(80,760 |
) |
|
Net purchase price
|
|
$ |
1,150,000 |
|
The Company has not disclosed the pro forma information for this acquisition because the revenue and expenses for this acquisition are immaterial to our interim consolidated financial statements.
4. Asset Retirement Obligations
The Company’s asset retirement obligations (“ARO”) relate to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. The fair value of a liability for an ARO is recorded in the period in which it is incurred, discounted to its present value using the credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.
The following table provides a rollforward of the AROs for the first nine months of fiscal 2013:
|
Carrying amount of asset retirement obligations as of April 1, 2012
|
|
$ |
663,279 |
|
|
Liabilities incurred
|
|
|
103,890 |
|
|
Liabilities settled
|
|
|
(447 |
) |
|
Accretion expense
|
|
|
28,822 |
|
|
Carrying amount of asset retirement obligations as of December 31, 2012
|
|
|
795,544 |
|
|
Less: Current portion
|
|
|
50,000 |
|
|
Non-Current asset retirement obligation
|
|
$ |
745,544 |
|
The ARO is included on the consolidated balance sheets with the current portion being included in the accounts payable and other accrued expenses.
5. Stock-based Compensation
The Company recognized compensation expense of $30,694 and $27,377 in general and administrative expense in the Consolidated Statements of Operations for the three months ended December 31, 2012 and 2011, respectively. Compensation expense recognized for the nine months ended December 31, 2012 and 2011 was $115,502 and $76,761, respectively. The total cost related to non-vested awards not yet recognized at December 31, 2012 totals approximately $134,445 which is expected to be recognized over a weighted average of 2.39 years.
The following table is a summary of activity of stock options for the nine months ended December 31, 2012:
| |
|
Number of Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Weighted Average Remaining Contract Life in Years
|
|
|
Aggregate
Intrinsic Value
|
|
|
Outstanding at March 31, 2012
|
|
|
83,750 |
|
|
$ |
6.42 |
|
|
|
8.65 |
|
|
$ |
127,363 |
|
|
Granted
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
3,750 |
|
|
|
4.35 |
|
|
|
|
|
|
|
|
|
|
Forfeited or Expired
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2012
|
|
|
80,000 |
|
|
$ |
6.52 |
|
|
|
8.27 |
|
|
$ |
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at December 30, 2012
|
|
|
30,000 |
|
|
$ |
6.42 |
|
|
|
8.07 |
|
|
$ |
550 |
|
|
Exercisable at December 30, 2012
|
|
|
30,000 |
|
|
$ |
6.42 |
|
|
|
8.07 |
|
|
$ |
550 |
|
During the nine months ended December 31, 2012, stock options covering 3,750 shares were exercised with a total intrinsic value of $3,138. The Company received proceeds of $16,313 from these exercises. During the nine months ended December 31, 2011, no stock options were exercised.
During the nine months ended December 31, 2012, no stock options were granted. During the nine months ended December 31, 2011, stock options covering 40,000 shares were granted.
Included in the following table is a summary of the grant-date fair value of stock options granted and the related assumptions used in the Binomial models for stock options granted during the nine months ended December 31, 2012 and 2011. All such amounts represent the weighted average amounts.
| |
Nine Months Ended
|
| |
December 31
|
| |
2012
|
2011
|
|
Grant-date fair value
|
-
|
$5.69
|
|
Volatility factor
|
-
|
85.92%
|
|
Dividend yield
|
-
|
-
|
|
Risk-free interest rate
|
-
|
1.49%
|
|
Expected term (in years)
|
-
|
7.25
|
The following table summarizes information about options outstanding at December 31, 2012:
|
Range of Exercise Prices
|
|
|
Number of Options
|
|
|
Weighted Average Exercise Price
|
|
|
Weighted Average Remaining Contract
Life in Years
|
|
|
Aggregate
Intrinsic Value
|
|
| $ |
6.06 – 6.29 |
|
|
|
40,000 |
|
|
$ |
6.23 |
|
|
|
|
|
|
|
| |
6.30 – 6.80 |
|
|
|
40,000 |
|
|
|
6.80 |
|
|
|
|
|
|
|
| $ |
5.25 – 6.80 |
|
|
|
80,000 |
|
|
$ |
6.52 |
|
|
|
8.27 |
|
|
$ |
— |
|
Outstanding options at December 31, 2012 expire between August 2020 and November 2021 and have exercise prices ranging from $6.06 to $6.80.
No forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types of awards. There were no stock options forfeited or expired during the nine months ended December 31, 2012 or 2011.
6. Fair Value of Financial Instruments
Fair value as defined by authoritative literature is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
Level 1 – Quoted prices in active markets for identical assets and liabilities.
Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
Level 3 – Significant inputs to the valuation model are unobservable.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. In accordance with the reporting requirements of FASB ASC Topic 825, Financial Instruments, the Company calculates the fair value of its assets and liabilities which qualify as financial instruments.
The initial measurement of asset retirement obligations’ fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the ARO liability is deemed to use Level 3 inputs. See the Company’s note on AROs for further discussion. AROs incurred during the nine months ended December 31, 2012 were approximately $104,000, of which approximately $80,000 were acquired through the business acquisition.
The carrying amount reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable and accounts payable and accrued expenses approximates fair value because of the immediate or short-term maturity of these financial instruments.
The carrying amount reported in the consolidated balance sheets for long term debt approximates fair value because the actual interest rates do not significantly differ from current rates offered for instruments with similar characteristics.
7. Credit Facility
The Company has a revolving credit agreement with Bank of America, N.A. (the “Agreement”), which provides for a credit facility of $4,900,000 with no monthly commitment reductions and a borrowing base evaluated annually, currently set at $4,900,000. Amounts borrowed under the Agreement are collateralized by the common stock of two of the Company’s wholly owned subsidiaries and substantially all of the Company’s oil and gas properties. Availability of this line of credit at December 31, 2012 was $2,000,000. No principal payments are anticipated to be required through November 30, 2014.
The Agreement was renewed six times with the sixth amendment on October 22, 2012, which revised the maturity date to November 30, 2014. Under the original and renewed agreements, interest on the facility accrues at an annual rate equal to the British Bankers Association London Interbank Offered Rate ("BBA LIBOR") daily floating rate, plus 2.50 percentage points, which was 2.712% on December 31, 2012. Interest on the outstanding amount under the credit agreement is payable monthly. In addition, the Company will pay an unused commitment fee in an amount equal to ½ of 1 percent (.5%) times the daily average of the unadvanced amount of the commitment. The unused commitment fee is payable quarterly in arrears on the last day of each calendar quarter.
The Agreement contains customary covenants for credit facilities of this type including limitations on disposition of assets, mergers and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement. The Company is in compliance with all covenants as of December 31, 2012. In addition, this Agreement prohibits the Company from paying cash dividends on our common stock. The Agreement does grant the Company permission to enter into hedge agreements; however, the Company is under no obligation to do so.
As of December 31, 2012, a letter of credit for $50,000, in lieu of a plugging bond with the Texas Railroad Commission covering the properties the Company operates is also outstanding under the facility. This letter of credit renews annually.
The balance outstanding on the line of credit as of December 31, 2012 was $2,900,000 and as of February 14, 2013 was $2,825,000.
The following table is a summary of activity on the Bank of America, N.A. line of credit for the nine months ended December 31, 2012:
| |
|
Principal
|
|
|
Balance at March 31, 2012:
|
|
$ |
1,700,000 |
|
|
Borrowings
|
|
|
1,450,000 |
|
|
Repayments
|
|
|
(250,000 |
) |
|
Balance at December 31, 2012:
|
|
$ |
2,900,000 |
|
8. 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.
The income tax provision consists of the following for the three and nine months ended December 31, 2012 and 2011:
| |
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
| |
|
December 31
|
|
|
December 31
|
|
| |
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
Current income tax (benefit) expense
|
|
$ |
— |
|
|
$ |
(4,858 |
) |
|
$ |
— |
|
|
$ |
124,880 |
|
|
Deferred income tax (benefit) expense
|
|
|
(51,965 |
) |
|
|
11,927 |
|
|
|
(150,083 |
) |
|
|
(50,109 |
) |
|
Total income tax provision:
|
|
$ |
(51,965 |
) |
|
$ |
7,069 |
|
|
$ |
(150,083 |
) |
|
$ |
74,771 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
(57 |
%) |
|
|
12 |
% |
|
|
(60 |
%) |
|
|
24 |
% |
The Company’s effective tax rate differs from the statutory rate primarily due to an increase in statutory depletion carryforward.
As of December 31, 2012, the Company has a statutory depletion carryforward of approximately $4,600,000, which does not expire. At December 31, 2012, there was a net operating loss carryforward for regular income tax reporting purposes of approximately $3,200,000, which will begin expiring in 2021. The Company’s ability to use the net operating loss carryforward and certain other tax attributes to reduce current and future U.S. federal taxable income is subject to limitations under the Internal Revenue Code.
Any interest and penalties related to uncertain tax positions are recorded as interest expense and general and administrative expense, respectively. As of December 31, 2012, the Company had unrecognized tax benefits of approximately $677,000.
9. Related Party Transactions
Related party transactions for the Company relate to shared office expenditures in addition to administrative and operating expenses paid on behalf of the majority stockholder. The total billed to and reimbursed by the stockholder for the nine months ended December 31, 2012 and 2011 was $112,359 and $94,691, respectively.
10. Income Per Common Share
Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted net income (loss) per share assumes the exercise of all stock options having exercise prices less than the average market price of the common stock during the period using the treasury stock method and is computed by dividing net income (loss) by the weighted average number of common shares and dilutive potential common shares (stock options) outstanding during the period. In periods where losses are reported, the weighted-average number of common shares outstanding excludes potential common shares, because their inclusion would be anti-dilutive.
The following is a reconciliation of the number of shares used in the calculation of basic income (loss) per share and diluted income (loss) per share for the three and nine month periods ended December 31, 2012 and 2011:
| |
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
| |
|
December 31
|
|
|
December 31
|
|
| |
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
Net (loss) income
|
|
$ |
(39,580 |
) |
|
$ |
50,961 |
|
|
$ |
(102,034 |
) |
|
$ |
234,618 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted avg. common shares outstanding – basic
|
|
|
2,036,938 |
|
|
|
2,026,011 |
|
|
|
2,036,277 |
|
|
|
2,028,626 |
|
|
Effect of the assumed exercise of dilutive stock options
|
|
|
- |
|
|
|
5,442 |
|
|
|
- |
|
|
|
9,368 |
|
|
Weighted avg. common shares outstanding – dilutive
|
|
|
2,036,938 |
|
|
|
2,031,453 |
|
|
|
2,036,277 |
|
|
|
2,037,994 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
(0.02 |
) |
|
$ |
0.03 |
|
|
$ |
(0.05 |
) |
|
$ |
0.12 |
|
|
Diluted
|
|
$ |
(0.02 |
) |
|
$ |
0.03 |
|
|
$ |
(0.05 |
) |
|
$ |
0.12 |
|
Due to a net loss for the three and nine months ended December 31, 2012, the weighted average number of common shares outstanding excludes common stock equivalents because their inclusion would be anti-dilutive. For the three and nine months ended December 31, 2011, 70,000 options were excluded from the diluted net income per share calculations because the options are anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $6.58 at December 31, 2011.
11. Subsequent Events
The Company completed a review and analysis of all events that occurred after the balance sheet date to determine if any such events must be reported and has determined that there are no subsequent events to be disclosed.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless the context otherwise requires, references to the “Company”, “Mexco”, “we”, “us” or “our” mean Mexco Energy Corporation and its consolidated subsidiaries.
Cautionary Statements Regarding Forward-Looking Statements. Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions. Forward-looking statements appear throughout this Form 10-Q with respect to, among other things: profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations. Forward-looking statements involve known and unknown risks and uncertainties that could cause actual results to differ materially from those contained in any forward-looking statement.
While we have made assumptions that we believe are reasonable, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. All forward-looking statements in the Form 10-Q are qualified in their entirety by the cautionary statement contained in this section. We do not undertake to update, revise or correct any of the forward-looking information. It is suggested that these financial statements be read in conjunction with the financial statements and notes thereto included in the Form 10-K.
Liquidity and Capital Resources. 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 its 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 in areas with significant development potential.
For the first nine months of fiscal 2013, cash flow from operations was $503,359, a 50% decrease when compared to the corresponding period of fiscal 2012. Cash of $949,372 was used for additions to oil and gas properties, $1,150,000 was used for the acquisition of a subsidiary and net proceeds from long term debt was $1,200,000. Accordingly, net cash decreased $393,506.
On December 31, 2012, the Company purchased all of the outstanding ownership interests of TBO Oil & Gas, LLC (“TBO”), a Texas limited liability company which owns non-operated working interests producing primarily oil. The cash purchase price of $1,150,000 was funded from our $4.9 million bank credit facility. These interests cover approximately 280 wells located in 16 counties in Texas, New Mexico and North Dakota.
On October 1, 2012, the Company sold all of its 31.25% working interest in the Brown #1 SWD wellbore in Ward County, Texas for approximately $47,000.
The Company also sold its interest in non-producing acreage in Culverson County, Texas and Richland County, Montana for approximately $15,000.
In March 2011, we purchased approximately 10.8% working interest (7.77% net revenue interest) in 160 gross acres containing five (5) wells in the Fuhrman-Mascho Field of Andrews County, Texas, for an approximate cash purchase price of $670,000 funded from our $4.9 million credit facility. In March 2012, we purchased an additional working interest in this acreage for an approximate cash purchase price of $275,000. We now own an approximate 16.2% working interest (11.66% net revenue interest). Two (2) additional wells were drilled during fiscal 2012 and another during the first quarter of fiscal 2013. Our share of the costs for this last well through December 31, 2012 was approximately $111,000. This acreage now contains eight (8) wells operated by Cone and Petree Oil & Gas Exploration, Inc. – four (4) producing oil from the San Andres formation and four (4) producing oil from the Grayburg and San Andres formations at an approximate depth of 5,000 feet. This property contains an additional eight (8) potential drill sites in the Grayburg and San Andres formations with five (5) planned to be drilled in fiscal 2013.
During the first nine months of fiscal 2013, we participated in 22 infill wells in the Yeso/Paddock formations of the Dodd-Federal Unit in the Grayburg San Andres Jackson Field of Eddy County, New Mexico. These wells were drilled to a total depth of approximately 5,000 feet. The unit, operated by Concho Resources, Inc., currently contains approximately 155 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 22 wells through December 31, 2012 was approximately $83,000.
During the first quarter of fiscal 2012, a joint venture in which we are a working interest partner began drilling the second of two (2) development wells in the Delaware and Bone Spring Sand formations on a 160-acre tract in Eddy County, New Mexico which currently contains four (4) producing wells. Our share of the costs to drill and complete both of these wells through December 2012 for our approximate 1% working interest was approximately $47,000.
In March 2012, we participated in the drilling of two (2) approximately 12,600’ development wells in the Cotton Valley-Bossier formation in the Teague Field of Freestone County, Texas. These wells have been completed and began producing in July 2012. The 680-acre unit, operated by Valence Operating Company, now contains 4 producing wells. Mexco’s working interest in this unit is 4.2% (3.7% net revenue interest). Our share of the costs to drill and complete these wells through December 31, 2012 was approximately $200,000.
Three joint ventures in which we are a working interest partner began drilling one (1) vertical and three (3) horizontal development wells in Lea County, New Mexico. One horizontal well is on a 560-acre tract and is to be completed in the Abo formation. Another horizontal well is to be completed in the Brushy Canyon formation. The other two wells are on a 640-acre tract which contains six wells currently producing and are to be completed in Bone Spring Sand formation. Our share of the costs to drill and complete these wells through December 31, 2012 for our approximate 1% working interest was approximately $222,000.
We acted as operator and drilled a development well in Pecos County, Texas in which Mexco owns 100% working interest (78.8% net revenue interest). This well is currently being completed and tested. Our costs to drill and complete this well through December 31, 2012 were approximately $1,055,000.
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 Mexco common stock.
On June 29, 2012, our board of directors authorized the use of up to $250,000 to repurchase shares of our common stock for the treasury account. During the nine months ended December 31, 2012, there were no shares repurchased for the treasury account. During the nine months ended December 31, 2011, we repurchased 4,000 shares for the treasury at an aggregate cost of $22,780.
At December 31, 2012, we had working capital of approximately $451,154 compared to working capital of $476,960 at March 31, 2012, a decrease of $25,806. This was mainly as a result of a decrease in cash and cash equivalents partially offset by an increase in oil and gas receivables, an increase in prepaid costs and expenses and a decrease in accounts payable and accrued expenses.
Crude oil and natural gas prices have fluctuated significantly in recent years. The effect of declining product prices on our business is significant. 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 $74.25 per bbl in June 2012 to a high of $105.25 per bbl in March 2012. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.82 per MMBtu in April 2012 to a high of $3.77 per MMBtu in November 2012. On December 30, 2012 the WTI posted price for crude oil was $88.50 per bbl and the Henry Hub spot price for natural gas was $3.43 per 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.
Contractual Obligations. 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 December 31, 2012:
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Payments Due In (1):
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| |
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Total
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less than 1 year
|
|
|
1-3 years
|
|
|
3 years
|
|
|
Contractual obligations:
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|
|
|
|
|
|
|
|
|
|
|
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Secured bank line of credit
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|
$ |
2,900,000 |
|
|
$ |
— |
|
|
$ |
2,900,000 |
|
|
$ |
— |
|
|
(1)
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Does not include estimated interest of $79,000 less than 1 year and $236,000 1-3 years.
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These amounts represent the balances outstanding under the bank line of credit. These repayments assume that interest will be paid on a monthly basis and that no additional funds will be drawn.
Results of Operations – Three Months Ended December 31, 2012 and 2011. For the quarter ended December 31, 2012, there was a net loss of $39,580 compared to net income of $50,961 for the quarter ended December 31, 2011. This decrease was a result of an increase in production costs and DD&A partially offset by a 9.5% increase in oil revenues.
Oil and gas sales. Revenue from oil and gas sales was $781,426 for the third quarter of fiscal 2013, a 3% increase from $753,789 for the same period of fiscal 2012. This resulted from an increase in oil and gas production partially offset by a decrease in oil and gas price.
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2012
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|
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2011
|
|
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% Difference
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Oil:
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|
|
|
|
|
|
|
|
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Revenue
|
|
$ |
474,194 |
|
|
$ |
432,968 |
|
|
|
9.5 |
% |
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Volume (bbls)
|
|
|
5,827 |
|
|
|
4,727 |
|
|
|
23.3 |
% |
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Average Price (per bbl)
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|
$ |
81.38 |
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|
$ |
91.59 |
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(11.1 |
%) |
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Gas:
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|
|
|
|
|
|
|
|
|
|
|
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Revenue
|
|
$ |
307,232 |
|
|
$ |
320,821 |
|
|
|
(4.2 |
%) |
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Volume (mcf)
|
|
|
104,951 |
|
|
|
95,308 |
|
|
|
10.1 |
|
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Average Price (per mcf)
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|
$ |
2.93 |
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|
$ |
3.37 |
|
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(13.1 |
%) |
Production and exploration. Production costs were $325,712 for the third quarter of fiscal 2013, a 40% increase from $233,317 for the same period of fiscal 2012. This was primarily the result of repairs on our operated well in Pecos County, Texas.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was $283,498 for the third quarter of fiscal 2013, a 27% decrease from $223,181 for the same period of fiscal 2012, due to an increase in oil and gas production and an increase to the full cost amortization base.
General and administrative expenses. General and administrative expenses were $250,183 for the third quarter of fiscal 2013, a 10% increase from $227,928 for the same period of fiscal 2012. This was primarily due to an increase in salaries and accounting fees.
Interest expense. Interest expense was $13,078 for the third quarter of fiscal 2013, a 123% increase from $5,854 for the same period of fiscal 2012, due to an increase in borrowings.
Income taxes. There was an income tax benefit of $51,965, or (57%), for the quarter ended December 31, 2012 compared to an income tax income tax expense of $7,069, or 12%, for the quarter ended December 31, 2011. This change in our effective tax rate was primarily the result of an increase in statutory depletion carryforward.
Results of Operations – Nine Months Ended December 31, 2012 and 2011. For the nine months ended December 31, 2012, there was a net loss of $102,034 compared to net income of $234,618 for the nine months ended December 31, 2011. This was a result of a decrease in operating revenues.
Oil and gas sales. Revenue from oil and gas sales was $2,139,609 for the nine months ended December 31, 2012, a 13% decrease from $2,469,784 for the same period of fiscal 2012. This resulted from a decrease in oil and gas price and a decrease in gas production partially offset by an increase in oil production.
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2012
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|
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2011
|
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% Difference
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Oil:
|
|
|
|
|
|
|
|
|
|
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Revenue
|
|
$ |
1,372,782 |
|
|
$ |
1,295,952 |
|
|
|
5.9 |
% |
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Volume (bbls)
|
|
|
16,252 |
|
|
|
14,211 |
|
|
|
14.4 |
% |
|
Average Price (per bbl)
|
|
$ |
84.47 |
|
|
$ |
91.19 |
|
|
|
(7.4 |
%) |
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|
|
|
|
|
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Gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
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Revenue
|
|
$ |
766,827 |
|
|
$ |
1,173,832 |
|
|
|
(34.7 |
%) |
|
Volume (mcf)
|
|
|
295,457 |
|
|
|
304,761 |
|
|
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(3.1 |
%) |
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Average Price (per mcf)
|
|
$ |
2.60 |
|
|
$ |
3.85 |
|
|
|
(32.5 |
%) |
Production and exploration. Production costs were $796,074 for the nine months ended December 31, 2012, a 14% increase from $697,548 for the nine months ended December 31, 2011. This was primarily the result of repairs on our El Cinco operated wells in Pecos County, Texas during the nine months of fiscal 2013.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was $774,814 for the nine months ended December 31, 2012, a 10% increase from $702,362 for the nine months ended December 31, 2011. This was due to an increase in oil production and an increase in the full cost pool amortization base partially offset by a slight decrease in gas production.
General and administrative expenses. General and administrative expenses were $779,161 for the nine months ended December 31, 2012, an 8% increase from $723,489 for the nine months ended December 31, 2011. This was due to an increase in stock option compensation expense.
Interest expense. Interest expense was $34,704 for the nine months ended December 31, 2012, a 53% increase from $22,735 for the nine months ended December 31, 2011 due to an increase in borrowings.
Income taxes. There was an income tax benefit of $150,083, or (60%), for the nine months ended December 31, 2012 compared to an income tax expense of $74,771, or 24%, for the nine months ended December 31, 2011. This change in our effective tax rate was primarily the result of an increase in statutory depletion carryforward.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The primary sources of market risk for us include fluctuations in commodity prices and interest rates. All of our financial instruments are for purposes other than trading. At December 31, 2012, we had not entered into any hedge arrangements, commodity swap agreements, commodity futures, options or other similar agreements relating to crude oil and natural gas.
Interest Rate Risk. At December 31, 2012, we had an outstanding loan balance of $2,900,000 under our $4.9 million revolving credit agreement, which bears interest at an annual rate equal to the BBA LIBOR daily floating rate, plus 2.50 percentage points. If the interest rate on our bank debt increases or decreases by one percentage point, our annual pretax income would change by $29,000 based on the outstanding balance at December 31, 2012.
Credit Risk. Credit risk is the risk of loss as a result of nonperformance by other parties of their contractual obligations. Our primary credit risk is related to oil and gas production sold to various purchasers and the receivables are generally not collateralized. At December 31, 2012, our largest credit risk associated with any single purchaser was $57,780 or 11% of our total oil and gas receivables. We are also exposed to credit risk in the event of nonperformance from any of our working interest partners. At December 31, 2012, our largest credit risk associated with any working interest partner was $3,345 or 18% of our total trade receivables. We have not experienced any significant credit losses.
Energy Price Risk. Our most significant market risk is the pricing for natural gas and crude oil. Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. Prices for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall political and economic conditions in oil producing countries. Declines in oil and natural gas prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our acquisition, exploration and development activities. In addition, a noncash write-down of our oil and gas properties could be required under full cost accounting rules if prices declined significantly, even if it is only for a short period of time. Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance.
Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Our financial results are more sensitive to movements in natural gas prices than oil prices because most of our production and reserves are natural gas. If the average oil price had increased or decreased by one dollar per barrel for the first nine months of fiscal 2013, our net income would have changed by $16,252. If the average gas price had increased or decreased by one dollar per mcf for the first nine months of fiscal 2013, our net income would have changed by $295,457.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. We maintain disclosure controls and procedures to ensure that the information we must disclose in our filings with the SEC is recorded, processed, summarized and reported on a timely basis. At the end of the period covered by this report, our principal executive officer and principal financial officer reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e). Based on such evaluation, such officers concluded that, as of December 31, 2012, our disclosure controls and procedures were effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is disclosed within the time periods specified in the SEC’s rules and forms and are effective to ensure that information required to be disclosed by us is accumulated and communicated to them to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting. No changes in our internal control over financial reporting occurred during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II – OTHER INFORMATION
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Item 1.
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Legal Proceedings
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We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. We are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under various environmental protection statutes or other regulations to which we are subject.
There have been no material changes to the information previously disclosed in Item 1A. “Risk Factors” in our 2012 Annual Report on Form 10-K.
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Item 2.
|
Unregistered Sales of Equity Securities and Use of Proceeds
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None
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Item 3.
|
Defaults Upon Senior Securities
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None
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Item 4.
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Mine Safety Disclosures
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None
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Item 5.
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Other Information
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None
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31.1
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Certification of the Chief Executive Officer of Mexco Energy Corporation
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31.2
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Certification of the Chief Financial Officer of Mexco Energy Corporation
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32.1
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Certification of the Chief Executive Officer and Chief Financial Officer of Mexco Energy Corporation pursuant to 18 U.S.C. §1350
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SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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MEXCO ENERGY CORPORATION
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(Registrant)
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Dated: February 14, 2013
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/s/ Nicholas C. Taylor
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Nicholas C. Taylor
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Chairman of the Board and Chief Executive Officer
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Dated: February 14, 2013
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/s/ Tamala L. McComic
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|
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Tamala L. McComic
|
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President, Chief Financial Officer, Treasurer and Assistant Secretary
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18