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.
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 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 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, 2013, and the results of its operations and cash flows for the interim periods ended December 31, 2013 and 2012. The financial statements as of December 31, 2013 and for the three and nine month periods ended December 31, 2013 and 2012 are unaudited. The consolidated balance sheet as of March 31, 2013 was derived from the audited balance sheet filed in the Company’s 2013 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.
Derivatives. The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. 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 change in fair value on derivative instruments in the consolidated statements of operations.
Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivatives and long term debt. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. Derivatives are recorded at fair value (see the Company’s Note 5 on Fair Value Measurements).
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 as of December 31, 2013 and March 31, 2013.
Recent Accounting Pronouncements. In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-11, Topic 740: Presentation of an Unrecognized Tax Benefit when a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. ASU No. 2013-11 clarifies the presentation of unrecognized tax benefits and is effective for interim periods beginning after December 15, 2013. The Company does not anticipate the guidance to have a significant impact on its financial position or results of operations.
There were no other accounting standards and interpretations issued during the reporting period which were applicable to the Company.
3. 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 2014:
|
Carrying amount of asset retirement obligations as of April 1, 2013
|
|
$ |
813,412 |
|
|
Liabilities incurred
|
|
|
13,057 |
|
|
Liabilities settled
|
|
|
(3,235 |
) |
|
Accretion expense
|
|
|
33,011 |
|
|
Carrying amount of asset retirement obligations as of December 31, 2013
|
|
|
856,245 |
|
|
Less: Current portion
|
|
|
50,000 |
|
|
Non-Current asset retirement obligation
|
|
$ |
806,245 |
|
The ARO is included on the consolidated balance sheets with the current portion being included in the accounts payable and other accrued expenses.
4. Stock-based Compensation
The Company recognized compensation expense of $37,080 and $30,694 in general and administrative expense in the Consolidated Statements of Operations for the three months ended December 31, 2013 and 2012, respectively. Compensation expense recognized for the nine months ended December 31, 2013 and 2012 was $119,318 and $115,502, respectively. The total cost related to non-vested awards not yet recognized at December 31, 2013 totals $158,574 which is expected to be recognized over a weighted average of 2.46 years.
The fair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are based on historical volatility of the Company’s stock over the expected term of 84 months for employees and 96 months for directors and other factors. We use historical data to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. As the Company has never declared dividends, no dividend yield is used in the calculation. Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Binomial model.
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, 2013 and 2012. All such amounts represent the weighted average amounts.
| |
|
Nine Months Ended
|
|
| |
|
December 31
|
|
| |
|
2013
|
|
|
2012
|
|
|
Grant-date fair value
|
|
$ |
4.75 |
|
|
|
- |
|
|
Volatility factor
|
|
|
77.01 |
% |
|
|
- |
|
|
Dividend yield
|
|
|
- |
|
|
|
- |
|
|
Risk-free interest rate
|
|
|
1.74 |
% |
|
|
- |
|
|
Expected term (in years)
|
|
|
7 |
|
|
|
- |
|
The following table is a summary of activity of stock options for the nine months ended December 31, 2013:
| |
|
Number
of Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Weighted Average Remaining Contract Life in Years
|
|
|
Aggregate
Intrinsic Value
|
|
|
Outstanding at March 31, 2013
|
|
|
80,000 |
|
|
$ |
6.52 |
|
|
|
8.03 |
|
|
$ |
- |
|
|
Granted
|
|
|
35,000 |
|
|
|
5.98 |
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Forfeited or Expired
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2013
|
|
|
115,000 |
|
|
$ |
6.35 |
|
|
|
7.89 |
|
|
$ |
62,900 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at December 31, 2013
|
|
|
50,000 |
|
|
$ |
6.46 |
|
|
|
7.15 |
|
|
$ |
22,025 |
|
|
Exercisable at December 31, 2013
|
|
|
50,000 |
|
|
$ |
6.46 |
|
|
|
7.15 |
|
|
$ |
22,025 |
|
During the nine months ended December 31, 2013, stock options covering 35,000 shares were granted. During the nine months ended December 31, 2012, no stock options were granted.
During the nine months ended December 31, 2013, no stock options were exercised. 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.
The following table summarizes information about options outstanding at December 31, 2013:
|
Range of Exercise Prices
|
|
|
Number of Options
|
|
|
Weighted Average Exercise Price
|
|
|
Weighted Average Remaining Contract
Life in Years
|
|
|
Aggregate
Intrinsic Value
|
|
| $ |
5.98 – 6.25 |
|
|
|
45,000 |
|
|
$ |
6.00 |
|
|
|
|
|
|
|
| |
6.26 – 6.50 |
|
|
|
30,000 |
|
|
|
6.29 |
|
|
|
|
|
|
|
| |
6.51 – 6.80 |
|
|
|
40,000 |
|
|
|
6.80 |
|
|
|
|
|
|
|
| $ |
5.98 – 6.80 |
|
|
|
115,000 |
|
|
$ |
6.35 |
|
|
|
7.89 |
|
|
$ |
62,900 |
|
Outstanding options at December 31, 2013 expire between August 2020 and April 2023 and have exercise prices ranging from $5.98 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, 2013 or 2012.
5. 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 fair value of the Company’s crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. The valuation of the Company’s derivative instrument is deemed to use Level 2 inputs. See the Company’s Note 8 on Derivatives for further discussion. The unrealized loss on derivatives for the nine months ended December 31, 2013 was approximately $38,000.
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, 2013 were approximately $13,000.
6. 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 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, 2013 was $2,819,333. No principal payments are anticipated to be required through November 30, 2015.
The Agreement was renewed seven times with the seventh amendment on October 25, 2013, which revised the maturity date to November 30, 2015. 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 2.669% on December 31, 2013. 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, 2013. 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.
The amended Agreement allows for up to $500,000 of the facility to be used for outstanding letters of credits. As of December 31, 2013, two letters of credit for $50,000 and $105,667, in lieu of plugging bonds with the Texas Railroad Commission (“TRRC”) covering the properties the Company operates are outstanding under the facility. These letters of credit renew annually. The Company will pay a fee in an amount equal to 1 percent (1.0%) per annum of the outstanding undrawn amount of each standby letter of credit, payable monthly in arrears, on the basis of the face amount outstanding on the day the fee is calculated.
The balance outstanding on the line of credit as of December 31, 2013 was $1,925,000 and as of February 13, 2014 was $1,575,000.
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, 2013:
| |
|
Principal
|
|
|
Balance at March 31, 2013:
|
|
$ |
2,950,000 |
|
|
Borrowings
|
|
|
- |
|
|
Repayments
|
|
|
(1,025,000 |
) |
|
Balance at December 31, 2013:
|
|
$ |
1,925,000 |
|
7. 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 related to uncertain tax positions are recorded as interest expense and general and administrative expense, respectively.
The income tax provision consists of the following for the three and nine months ended December 31, 2013 and 2012:
| |
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
| |
|
December 31
|
|
|
December 31
|
|
| |
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
Current income tax
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
Deferred income tax expense (benefit)
|
|
|
9,474 |
|
|
|
(51,965 |
) |
|
|
(42,783 |
) |
|
|
(150,083 |
) |
|
Total income tax provision:
|
|
$ |
9,474 |
|
|
$ |
(51,965 |
) |
|
$ |
(42,783 |
) |
|
$ |
(150,083 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
10 |
% |
|
|
(57 |
%) |
|
|
(17 |
%) |
|
|
(60 |
%) |
As of December 31, 2013, the Company has a statutory depletion carryforward of approximately $4,800,000, which does not expire. At December 31, 2013, there was a net operating loss carryforward for regular income tax reporting purposes of approximately $2,900,000, 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. As of December 31, 2013, the Company had unrecognized tax benefits of approximately $677,000.
8. Derivatives
All derivative financial instruments are recorded at fair value. 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 “Gain/loss on derivative instruments.”
The Company uses price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the Company’s fixed price swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”) pricing. The counterparty to the Company’s derivative contract is Merrill Lynch Commodities, Inc., who the Company believes is an acceptable credit risk.
As of December 31, 2013 the Company had the following open crude oil derivative positions with respect to future production based on NYMEX WTI pricing:
| |
|
Volume
(bbls)
|
|
|
Fixed Swap
Price
|
|
|
Production Period
|
|
|
|
|
|
|
|
December 2013 – March 2015
|
|
|
8,000 |
|
|
$ |
90.00 |
|
The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.
The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
| |
|
As of
|
|
|
As of
|
|
| |
|
December 31,
|
|
|
March 31,
|
|
| |
|
2013
|
|
|
2013
|
|
|
Current assets: Derivative instruments
|
|
$ |
- |
|
|
$ |
- |
|
|
Noncurrent assets: Derivative instruments
|
|
|
- |
|
|
$ |
- |
|
|
Total assets
|
|
$ |
- |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
Current liabilities: Derivative instruments
|
|
$ |
36,186 |
|
|
$ |
- |
|
|
Noncurrent liabilities: Derivative instruments
|
|
|
1,837 |
|
|
$ |
- |
|
|
Total liabilities
|
|
$ |
38,023 |
|
|
$ |
- |
|
None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative instruments included in the consolidated statements of operations for the nine months ended December 31, 2013 and 2012:
| |
|
2013
|
|
|
2012
|
|
|
Unrealized loss on open non-hedge derivative instruments
|
|
$ |
(38,023 |
) |
|
$ |
- |
|
|
Loss on settlement of non-hedge derivative instruments
|
|
|
(41,261 |
) |
|
$ |
- |
|
|
Total loss on derivative instruments
|
|
$ |
(79,284 |
) |
|
$ |
- |
|
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, 2013 and 2012 was $105,288 and $112,359, respectively.
10. Income (Loss) 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, 2013 and 2012:
| |
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
| |
|
December 31
|
|
|
December 31
|
|
| |
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
Net income (loss)
|
|
$ |
88,659 |
|
|
$ |
(39,580 |
) |
|
$ |
298,841 |
|
|
$ |
(102,034 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted avg. common shares outstanding – basic
|
|
|
2,036,866 |
|
|
|
2,036,938 |
|
|
|
2,036,866 |
|
|
|
2,036,277 |
|
|
Effect of the assumed exercise of dilutive stock options
|
|
|
6,506 |
|
|
|
- |
|
|
|
3,458 |
|
|
|
- |
|
|
Weighted avg. common shares outstanding – dilutive
|
|
|
2,043,372 |
|
|
|
2,036,938 |
|
|
|
2,040,324 |
|
|
|
2,036,277 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.04 |
|
|
$ |
(0.02 |
) |
|
$ |
0.15 |
|
|
$ |
(0.05 |
) |
|
Diluted
|
|
$ |
0.04 |
|
|
$ |
(0.02 |
) |
|
$ |
0.15 |
|
|
$ |
(0.05 |
) |
For the three and nine months ended December 31, 2013, 75,000 potential common shares relating to stock options were excluded in the computation of diluted net income because the options are anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $6.42 at December 31, 2013. 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.
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 and working interests in non-operated properties in areas with significant development potential.
At December 31, 2013, we had working capital of approximately $776,729 compared to working capital of $309,180 at March 31, 2013, an increase of $467,549 for the reasons set forth below.
For the first nine months of fiscal 2014, cash flow from operations was $1,137,157, a 126% increase when compared to the corresponding period of fiscal 2013. Cash of $1,025,000 was used to reduce the balance on the line of credit; net cash of $26,829 was used for additions to oil and gas properties and equipment; and cash of $41,261 was used for settlement of derivatives. Accordingly, net cash increased $44,067.
Texas
On 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, Texas in return for payment to Mexco of $1,500 per acre totaling $625,995. Mexco retained a 1% royalty. This interest has potential for oil production from the Horizontal Wolfcamp trend of the Permian Basin in 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 $330,958 in cash and retained minor royalties as payment for our share of the leasehold acreage.
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 December 31, 2013 was approximately $148,000.
We participated in the drilling of seven (7) 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 one (1) well still being drilled. The seven units, six operated by OGX Operating, LLC and 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 December 31, 2013 was approximately $78,000.
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. The two units, one operated by McClure Oil Company, Inc. and one operated by Nadel and Gussman Permian LLC, contains 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 December 31, 2013 was approximately $22,000.
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 producing with the other well still being drilled. 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 December 31, 2013 was approximately $111,000. 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 fiscal 2014.
In December 2013, a joint venture in which we are a working interest owner began drilling two (2) of the four (4) planned development wells in the Atoka/Bend through Spraberry formations on 640 acres in Reagan County, Texas. Our share of the costs to begin drilling these wells through December 31, 2013 for our approximate .3% working interest (.24% net revenue interest) was approximately $37,000.
New Mexico
We participated in the drilling of nine (9) horizontal wells in the Bone Springs formation of Lea County, New Mexico. Five (5) of these wells are operated by COG Operating, LLC, three (3) are operated by Cimarex Energy and one (1) is operated by Manzano, LLC. All nine (9) of these wells have been completed and are currently producing. Subsequently, in January 2014, Cimarex announced plans to drill another well 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 December 31, 2013 was approximately $73,000.
A joint venture in which we are a working interest partner entered into a joint development agreement to develop the Avalon Shale portion 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 12 prospective drill sites on this acreage. Our share of the costs to drill the first well through September 2013 for 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. Nine (9) vertical and three (3) horizontal wells were drilled during the first six months of fiscal 2014 to a total 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 twelve wells through December 31, 2013 was approximately $38,000.
Oklahoma
We participated in the drilling of three (3) horizontal wells in a 640 acre unit in the Cottage Grove formation 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 December 2013 was approximately $121,000.
North Dakota
We are scheduled to participate in six (6) horizontal infill wells on a 1,280-acre unit and four (4) horizontal infill wells on a 1,920-acre unit in the Bakken and Three Forks formations of the Catwalk Creek Field of Williams County, North Dakota. The first of these wells on a 15-month schedule began drilling in June 2013. Mexco’s working interest in the 1,280-acre unit is .234% (.205% net revenue interest) and .0521% (.0453% net revenue interest) in the 1,920-acre unit. As of December 31, 2013, our share of the costs associated with these wells was approximately $6,000.
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.
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 $83.25 per bbl in April 2013 to a high of $107.00 per bbl in September 2013. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $3.14 per MMBtu in January 2013 to a high of $4.52 per MMBtu in December 2013. On December 31, 2013 the WTI posted price for crude oil was $95.00 per bbl and the Henry Hub spot price for natural gas was $4.52 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, 2013:
| |
|
Payments Due In (1):
|
|
| |
|
Total
|
|
|
less than 1 year
|
|
|
1-3 years
|
|
|
3 years
|
|
|
Contractual obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Secured bank line of credit
|
|
$ |
1,925,000 |
|
|
$ |
— |
|
|
$ |
1,925,000 |
|
|
$ |
— |
|
|
(1)
|
Does not include estimated interest of $51,000 less than 1 year and $154,000 1-3 years.
|
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, 2013 and 2012. For the quarter ended December 31, 2013, there was a net income of $88,659 compared to a net loss of $39,580 for the quarter ended December 31, 2012. This increase was a result of an increase in operating revenues.
Oil and gas sales. Revenue from oil and gas sales was $948,633 for the third quarter of fiscal 2014, a 21% increase from $781,426 for the same period of fiscal 2013. This resulted from an increase in oil and gas prices and oil production partially offset by a decrease in gas production.
| |
|
2013
|
|
|
2012
|
|
|
% Difference
|
|
|
Oil:
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$ |
629,765 |
|
|
$ |
474,194 |
|
|
|
32.8 |
% |
|
Volume (bbls)
|
|
|
6,808 |
|
|
|
5,827 |
|
|
|
16.8 |
% |
|
Average Price (per bbl)
|
|
$ |
92.51 |
|
|
$ |
81.38 |
|
|
|
13.7 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$ |
318,868 |
|
|
$ |
307,232 |
|
|
|
3.8 |
% |
|
Volume (mcf)
|
|
|
89,059 |
|
|
|
104,951 |
|
|
|
(15.1 |
%) |
|
Average Price (per mcf)
|
|
$ |
3.58 |
|
|
$ |
2.93 |
|
|
|
22.2 |
% |
Production and exploration. Production costs were $291,828 for the third quarter of fiscal 2014, a 10% decrease from $325,712 for the same period of fiscal 2013. This was primarily the result of repairs on one of our operated wells in Pecos County, Texas during the quarter ended December 31, 2012.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was $277,557 for the third quarter of fiscal 2014, a 2% decrease from $283,498 for the same period of fiscal 2013, due to a decrease in gas production partially offset by an increase in oil production and a decrease to the full cost amortization base.
General and administrative expenses. General and administrative expenses were $275,489 for the third quarter of fiscal 2014, a 10% increase from $250,183 for the same period of fiscal 2013. This was primarily due to an increase in insurance, salaries and employee stock option compensation expense.
Interest expense. Interest expense was $15,353 for the third quarter of fiscal 2014, a 17% increase from $13,078 for the same period of fiscal 2013, due to an increase in borrowings.
Income taxes. There was an income tax expense of $9,474, or 10%, for the quarter ended December 31, 2013 compared to an income tax benefit of $51,965, or (57%), for the quarter ended December 31, 2012. This change in our effective tax rate was primarily the result of an increase in statutory depletion carryforward in December 2012.
Derivatives. Derivative gains of $7,404 were recorded during the three months ended December 31, 2013. This amount reflects $11,189 of realized losses and $18,593 of unrealized gains resulting from our oil swap agreement.
Results of Operations – Nine Months Ended December 31, 2013 and 2012. For the nine months ended December 31, 2013, there was net income of $298,841, an increase from a net loss of $102,034 for the nine months ended December 31, 2012. This was a result of an increase in operating revenues.
Oil and gas sales. Revenue from oil and gas sales was $3,041,004 for the nine months ended December 31, 2013, a 42% increase from $2,139,609 for the same period of fiscal 2013. This resulted from an increase in oil and gas prices and oil production partially offset by a decrease in gas production.
| |
|
2013
|
|
|
2012
|
|
|
% Difference
|
|
|
Oil:
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$ |
2,018,523 |
|
|
$ |
1,372,782 |
|
|
|
47.0 |
% |
|
Volume (bbls)
|
|
|
20,947 |
|
|
|
16,252 |
|
|
|
28.9 |
% |
|
Average Price (per bbl)
|
|
$ |
96.36 |
|
|
$ |
84.47 |
|
|
|
14.1 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$ |
1,022,481 |
|
|
$ |
766,827 |
|
|
|
33.3 |
% |
|
Volume (mcf)
|
|
|
281,643 |
|
|
|
295,457 |
|
|
|
(4.7 |
%) |
|
Average Price (per mcf)
|
|
$ |
3.63 |
|
|
$ |
2.60 |
|
|
|
39.6 |
% |
Production and exploration. Production costs were $913,418 for the nine months ended December 31, 2013, a 15% increase from $796,074 for the nine months ended December 31, 2012. This was primarily the result of an increase in production taxes due to the increase in oil and gas revenues and an increase in operating expenses due to the additional working interest wells from the TBO acquisition.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was $871,079 for the nine months ended December 31, 2013, a 12% increase from $774,814 for the nine months ended December 31, 2012, primarily due to an increase in oil production and an increase in the full cost pool amortization base partially offset by a decrease in gas production.
General and administrative expenses. General and administrative expenses were $873,573 for the nine months ended December 31, 2013, an 12% increase from $779,161 for the nine months ended December 31, 2012. This was primarily due to an increase in accounting and engineering services, insurance, salaries and employee stock option compensation expense.
Interest expense. Interest expense was $53,685 for the nine months ended December 31, 2013, a 55% increase from $34,704 for the nine months ended December 31, 2012 due to an increase in borrowings.
Income taxes. There was an income tax benefit of $42,783, or (17%), for the nine months ended December 31, 2013 compared to an income tax benefit of $150,083, or (60%), for the nine months ended December 31, 2012. This change in our effective tax rate was primarily the result of an increase in statutory depletion carryforward.
Derivatives. Derivative losses of $79,284 were recorded during the nine months ended December 31, 2013. This amount reflects $41,261 of realized losses and $38,023 of unrealized losses resulting from our oil swap agreement.
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.
Interest Rate Risk. At December 31, 2013, we had an outstanding loan balance of $1,925,000 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 $19,250 based on the outstanding balance at December 31, 2013.
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, 2013, our largest credit risk associated with any single purchaser was $214,659 or 29% 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, 2013, our largest credit risk associated with any working interest partner was $2,779 or 20% of our total trade receivables. We have not experienced any significant credit losses.
Commodity 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 2014, our net income would have changed by $20,947. If the average gas price had increased or decreased by one dollar per mcf for the first nine months of fiscal 2014, our net income would have changed by $281,643.
We use price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. In March 2013, we placed a commodity swap contract covering a total of 12,000 bbls of crude oil for the period from April 2013 to March 2015 at a fixed price of $90.00 per bbl. Such contracts and any future swap arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil.
At December 31, 2013, we had a net liability derivative position of $38,023 related to our price swap derivatives. Utilizing actual derivative contractual volumes as of December 31, 2013, a 10% increase or decrease in forward curves associated with the underlying commodity would have changed the net liability of these instruments by approximately $71,000. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.
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(f). Based on such evaluation, such officers concluded that, as of December 31, 2013, 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, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II – OTHER INFORMATION
|
Item 1.
|
Legal Proceedings
|
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 2013 Annual Report on Form 10-K other than those set forth below:
We have entered into price swap derivatives and may in the future enter into additional price swap derivatives for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil.
We use price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty.
In March 2013, we placed a commodity swap contract covering a total of 12,000 bbls of crude oil for the period from April 2013 to March 2015 at a fixed price of $90.00 per bbl. Such contracts and any future swap arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.
Our derivative transactions expose us to counterparty credit risk.
Our derivative transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.
|
Item 2.
|
Unregistered Sales of Equity Securities and Use of Proceeds
|
None
|
Item 3.
|
Defaults Upon Senior Securities
|
None
|
Item 4.
|
Mine Safety Disclosures
|
None
|
Item 5.
|
Other Information
|
None
|
|
31.1
|
Certification of the Chief Executive Officer of Mexco Energy Corporation
|
|
|
31.2
|
Certification of the Chief Financial Officer of Mexco Energy Corporation
|
|
|
32.1
|
Certification of the Chief Executive Officer and Chief Financial Officer of Mexco Energy Corporation pursuant to 18 U.S.C. §1350
|
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.
| |
MEXCO ENERGY CORPORATION
|
|
| |
(Registrant)
|
|
| |
|
|
|
Dated: February 13, 2014
|
/s/ Nicholas C. Taylor
|
|
| |
Nicholas C. Taylor
|
|
| |
Chairman of the Board and Chief Executive Officer
|
| |
|
|
|
Dated: February 13, 2014
|
/s/ Tamala L. McComic
|
|
| |
Tamala L. McComic
|
|
| |
President, Chief Financial Officer, Treasurer and Assistant Secretary
|