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 thirteen 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 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, 2014, and the results of its operations and cash flows for the interim periods ended December 31, 2014 and 2013. The financial statements as of December 31, 2014 and for the three and nine month periods ended December 31, 2014 and 2013 are unaudited. The consolidated balance sheet as of March 31, 2014 was derived from the audited balance sheet filed in the Company’s 2014 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.
Recent Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Topic 606: Revenue from Contracts with Customers. ASU No. 2014-09 is effective for Mexco as of April 1, 2017. Management is evaluating the effect, if any this pronouncement will have on our consolidated financial statements.
In August 2014, the FABS issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 will explicitly require management to assess an entity’s ability to continue as a going concern, and to provide related footnote disclosure in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016. Earlier adoption is permitted. We are currently evaluating the impact of the adoption of ASU 2014-15.
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 2015:
|
Carrying amount of asset retirement obligations as of April 1, 2014
|
|
$
|
961,577
|
|
|
Liabilities incurred
|
|
|
270,924
|
|
|
Liabilities settled
|
|
|
(23,026
|
)
|
|
Accretion expense
|
|
|
17,663
|
|
|
Carrying amount of asset retirement obligations as of December 31, 2014
|
|
|
1,227,138
|
|
|
Less: Current portion
|
|
|
10,000
|
|
|
Non-Current asset retirement obligation
|
|
$
|
1,217,138
|
|
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 stock-based compensation expense of $45,775 and $37,080 in general and administrative expense in the Consolidated Statements of Operations for the three months ended December 31, 2014 and 2013, respectively. Stock-based compensation expense recognized for the nine months ended December 31, 2014 and 2013 was $109,928 and $119,318, respectively. The total cost related to non-vested awards not yet recognized at December 31, 2014 totals $239,064 which is expected to be recognized over a weighted average of 2.84 years.
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, 2014 and 2013. All such amounts represent the weighted average amounts.
| |
Nine Months Ended
December 31
|
| |
2014
|
2013
|
|
Grant-date fair value
|
$ 5.59
|
$4.75
|
|
Volatility factor
|
76.23%
|
77.01%
|
|
Dividend yield
|
-
|
-
|
|
Risk-free interest rate
|
2.52%
|
1.74%
|
|
Expected term (in years)
|
10
|
7
|
The following table is a summary of activity of stock options for the nine months ended December 31, 2014:
| |
|
Number
of
Shares
|
|
|
Weighted
Average
Exercise Price
|
|
|
Weighted Average Remaining Contract Life in Years
|
|
|
Aggregate
Intrinsic
Value
|
|
|
Outstanding at March 31, 2014
|
|
|
113,600
|
|
|
$
|
6.35
|
|
|
|
7.66
|
|
|
$
|
154,062
|
|
|
Granted
|
|
|
40,000
|
|
|
|
7.00
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Forfeited or Expired
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2014
|
|
|
153,600
|
|
|
$
|
6.52
|
|
|
|
7.61
|
|
|
$
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at December 31, 2014
|
|
|
77,350
|
|
|
$
|
6.42
|
|
|
|
6.44
|
|
|
$
|
-
|
|
|
Exercisable at December 31, 2014
|
|
|
77,350
|
|
|
$
|
6.42
|
|
|
|
6.44
|
|
|
$
|
-
|
|
During the nine months ended December 31, 2014, stock options covering 40,000 shares were granted. During the nine months ended December 31, 2013, stock options covering 35,000 shares were granted.
During the nine months ended December 31, 2014 and 2013, no stock options were exercised. Outstanding options at December 31, 2014 expire between August 2020 and August 2024 and have exercise prices ranging from $5.98 to $7.00.
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.
The carrying amount reported in the accompanying consolidated balance sheets for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments.
The fair value amount reported in the accompanying 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 and is deemed to use Level 2 inputs. See the Company’s Note 6 on Credit Facility for further discussion.
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.
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 $6,300,000 with no monthly commitment reductions and a borrowing base evaluated annually, currently set at $6,300,000. 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.
The Agreement was renewed eight times with the eighth amendment on September 10, 2014, which revised the maturity date to November 30, 2016. 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, 2014. 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 and is included in the consolidated statements of operations under the caption “General and administrative” expenses. Availability of this line of credit at December 31, 2014 was $500,000. No principal payments are anticipated to be required through November 30, 2016.
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, 2014. 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, 2014, one letter of credit for $50,000, in lieu of a plugging bond with the Texas Railroad Commission (“TRRC”) covering the properties the Company operates is outstanding under the facility. This letter of credit renews 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 following table is a summary of activity on the Bank of America, N.A. line of credit for the nine months ended December 31, 2014:
| |
|
Principal
|
|
|
Balance at March 31, 2014:
|
|
$
|
2,425,000
|
|
|
Borrowings
|
|
|
3,475,000
|
|
|
Repayments
|
|
|
(150,000
|
)
|
|
Balance at December 31, 2014:
|
|
$
|
5,750,000
|
|
7. Income Taxes
The income tax provision consists of the following for the three and nine months ended December 31, 2014 and 2013:
| |
|
Three Months Ended
December 31
|
|
Nine Months Ended
December 31
|
| |
|
2014
|
|
2013
|
|
2014
|
|
2013
|
| |
Current income tax
|
$ -
|
|
$ -
|
|
$ -
|
|
$ -
|
| |
Deferred income tax expense (benefit)
|
(13,856)
|
|
9,474
|
|
(21,759)
|
|
(42,783)
|
|
Total income tax provision:
|
$ (13,856)
|
|
$ 9,474
|
|
$ (21,759)
|
|
$ (42,783)
|
| |
|
|
|
|
|
|
|
|
Effective tax rate
|
(7%)
|
|
10%
|
|
(24%)
|
|
(17%)
|
The change in our effective tax rate was primarily the result of a change in statutory depletion carryforward for the nine months ended December 31, 2014.
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 has used 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, 2014 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
|
|
|
|
|
|
|
|
January 2015 – March 2015
|
|
|
1,500
|
|
|
$
|
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
December 31,
2014
|
|
|
As of
March 31,
2014
|
|
|
Current assets: Derivative instruments
|
|
$
|
57,849
|
|
|
$
|
-
|
|
|
Noncurrent assets: Derivative instruments
|
|
|
-
|
|
|
|
7,239
|
|
|
Total assets
|
|
$
|
57,849
|
|
|
$
|
7,239
|
|
| |
|
|
|
|
|
|
|
|
|
Current liabilities: Derivative instruments
|
|
$
|
-
|
|
|
$
|
44,981
|
|
|
Noncurrent liabilities: Derivative instruments
|
|
|
-
|
|
|
|
-
|
|
|
Total liabilities
|
|
$
|
-
|
|
|
$
|
44,981
|
|
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 three and nine months ended December 31, 2014 and 2013:
|
|
Three Months Ended
December 31
|
|
|
Nine Months Ended
December 31
|
|
| |
|
2014
|
|
|
2013
|
|
|
2014
|
|
|
2013
|
|
|
Unrealized gain (loss) on open non-hedge
derivative instruments
|
|
$
|
54,839
|
|
|
$
|
18,594
|
|
|
$
|
102,830
|
|
|
$
|
(38,023
|
)
|
|
Gain (loss) on settlement of non-hedge
derivative instruments
|
|
|
25,281
|
|
|
|
(11,190
|
)
|
|
|
(4,959
|
)
|
|
|
(41,261
|
)
|
|
Total gain (loss) on derivative instruments
|
|
$
|
80,120
|
|
|
$
|
7,404
|
|
|
$
|
97,871
|
|
|
$
|
(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, 2014 and 2013 was $100,510 and $105,288, respectively.
10. (Loss) Income Per Common Share
The Company’s basic net (loss) income per share has been computed by dividing net (loss) income by the weighted average number of common shares outstanding during the period. Diluted net (loss) income 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 (loss) income by the weighted average number of common share 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 net (loss) income per share and diluted (loss) income per share for the three and nine month periods ended December 31, 2014 and 2013:
| |
|
Three Months Ended
December 31
|
|
|
Nine Months Ended
December 31
|
|
| |
|
2014
|
|
|
2013
|
|
|
2014
|
|
|
2013
|
|
|
Net (loss) income
|
|
$
|
(175,321
|
)
|
|
$
|
88,659
|
|
|
$
|
(70,011
|
)
|
|
$
|
298,841
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted avg. common shares outstanding – basic
|
|
|
2,038,266
|
|
|
|
2,036,866
|
|
|
|
2,038,266
|
|
|
|
2,036,866
|
|
|
Effect of the assumed exercise of dilutive stock options
|
|
|
-
|
|
|
|
6,506
|
|
|
|
-
|
|
|
|
3,458
|
|
|
Weighted avg. common shares outstanding – dilutive
|
|
|
2,038,266
|
|
|
|
2,043,372
|
|
|
|
2,038,266
|
|
|
|
2,040,324
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.09
|
)
|
|
$
|
0.04
|
|
|
$
|
(0.03
|
)
|
|
$
|
0.15
|
|
|
Diluted
|
|
$
|
(0.09
|
)
|
|
$
|
0.04
|
|
|
$
|
(0.03
|
)
|
|
$
|
0.15
|
|
Due to a net loss for the three and nine months ended December 31, 2014, 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, 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 had a weighted average exercise price of $6.42 at December 31, 2013.
11. Subsequent Events
The Company’s loan agreement with Bank of America, N.A., which provides for a credit facility of $6,300,000 was amended on February 13, 2015 to revise the maturity date to November 30, 2020.
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.
For the first nine months of fiscal 2015, cash flow from operations was $908,521, a 20% decrease when compared to the corresponding period of fiscal 2014. Net cash of $3,325,000 was provided by the line of credit; net cash of $4,279,511 was used for activity associated with oil and gas properties and other property and equipment; and cash of $4,959 was used for settlement of derivatives. Accordingly, net cash decreased $50,949.
At December 31, 2014, we had working capital of approximately $354,702 compared to working capital of $522,216 at March 31, 2014, a decrease of $167,514 for the reasons set forth below.
Acquisitions
Effective August 2014, Mexco purchased various royalty interests for $200,000 covering 43 wells in 12 counties of eight states. Of these oil and gas reserves, approximately 54% are in Texas and 10% in Lousiana where there is acreage available for further development by horizontal drilling and fracturing. These royalty interests are free of expenses to Mexco for drilling and operations.
Effective September 2014, Mexco purchased various royalty interests ranging from .0018% to 1.1% revenue interests at a price of $580,000 covering approximately 580 wells in 87 counties of eight states. Of this oil and gas production, virtually all is natural gas. Mexco believes that there is potential for further development of several of these royalties. These royalty interests are free of expenses to Mexco for drilling and operations. Approximately 90% of the net revenue from these royalties is produced by 157 wells located in the Barnett Shale of the Fort Worth Basin of Texas. Also included are interests in 423 wells in Alabama, Arkansas, Kansas, Louisiana, Mississippi, North Dakota, Oklahoma and Texas.
Effective October 2014, Mexco purchased for $525,000 long lived non-operated working interests of 12.5% (approximately 10% net revenue interest). Six wells are producing oil from the Lower Tubb formation in Pecos County, Texas. These wells are on 20-acre spacing with four additional proven undeveloped locations at approximately 3,600 foot depth on the 190 acres. The operator has agreed to pay for the drilling and completion costs of one additional well and fracture treatment of one of the existing wells, as well as pay all operating expenses of all wells on these leases. In addition, Mexco will receive 100% of the gross disposal fees from one disposal well located on these properties paid by an adjacent operator. Mexco would be responsible for payment of the cost of drilling and completion on the balance of any development wells.
Effective October 2014, Mexco purchased various royalty interests at a price of $1,000,000 covering approximately 1,800 wells in 27 counties of Texas. Of these oil and gas reserves, approximately 80% is natural gas and 20% oil. Mexco believes that there is potential for further development of a number of these royalties especially through horizontal drilling and fracturing. These royalty interests are free of expenses to Mexco for drilling and operations. Approximately 15% of the net revenue from these royalties comes from 237 wells located in Reagan County, Texas. Also included are interests in 21 wells in Glasscock County, Texas. Both of these counties are in the horizontal Spraberry Wolfcamp trend. The second largest source of net income is in Webb County, Texas from 202 wells producing 13.5 % of net income. Royalties in Karnes County, Texas amount to approximately 5% of net revenue from interests in 30 wells. Both Karnes and Webb counties are in the Eagle Ford trend.
Effective November 2014, Mexco purchased various long-lived non-operated working interests at a price of $840,000 covering 70 wells in 5 counties of Oklahoma.
Development
Texas
A joint venture in which we are a working interest owner entered into an agreement to develop the Wolfcamp B formation using horizontal drilling and multi-stage fracture stimulation on a 1,125-acre tract in Reagan County, Texas. There are seven (7) prospective drill sites on this acreage planned to be drilled through calendar year 2015. Mexco paid $95,000 this quarter in connection with the drilling of a fourth well. Our share of the costs for the first three wells through December 31, 2014 and to purchase additional working interests for our approximate 1.45% working interest (1.25% net revenue interest) was approximately $409,000.
We participated in the drilling of ten horizontal wells and one vertical well in the Penn Detrital formation of the F A Hogg Field of Winkler County, Texas. Five wells have been completed and are currently producing. The other wells are undergoing completion operations. The seven units, operated by Apache Corporation, contain approximately 2,600 acres. Mexco’s working interest in these wells is .4167% (.3125% net revenue interest). Our share of the costs to drill and complete these wells through December 31, 2014 was approximately $117,000.
We own a 1.4% royalty interest in the deep rights of a 300-acre tract Spraberry trend formation of Howard County, Texas. This acreage currently contains two newly drilled vertical wells operated by Crownquest Operating, LLC. All of this acreage is free of expenses to Mexco for drilling, development and operations.
New Mexico
We agreed to participate in the drilling of two horizontal wells in the Bone Springs formation of Lea County, New Mexico. The two units, operated by Cimarex Energy, Co., contain approximately 800 acres. Both wells have been completed and are currently producing. Mexco’s working interests in these wells are .047% and .125% (.033% and .088% net revenue interest, respectively). Our committed share of the costs to drill and complete these wells is approximately $11,000.
A joint venture in which Mexco is a working interest owner 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 acreage in Lea County, New Mexico. There are eight prospective drill sites on this acreage. Mexco’s share of the costs for the first three wells was approximately $104,000 for our approximate 0.326% working interest (0.24% net revenue interest).
A joint venture in which Mexco is a working interest owner 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. The first three wells have been completed and are currently producing. Mexco’s share of the costs for these first three wells was approximately $126,000 for our approximate 0.56% working interest (0.42% net revenue interest).
A joint venture in which Mexco is a working interest partner entered into two other joint development agreements to develop the third and second portions of the Bone Spring formation, respectively, using horizontal drilling and multi-stage fracture stimulation on two tracts containing approximately 400 acres in Lea County, New Mexico. There are currently 3 wells planned to be drilled on this acreage. Two wells operated by XTO Energy, Inc. and the other well operated by Endurance Resources, Inc. Mexco’s share of the costs for the first two wells through December 31, 2014 and to purchase additional working interests for our working interests ranging from 1.12% to 2.78% (.95% to 2.42% net revenue interest) was $228,700.
We agreed to participate in the drilling of a horizontal well in the Willow Lake Pool of the Second Bone Spring Sand formation of Eddy County, New Mexico. The lease, operated by Nadel and Gussman Permian, LLC, contains approximately 240 acres with one producing well. One hundred sixty of these acres are dedicated to the new well unit. Mexco’s working interest in the new well is .117% (approximately .094% net revenue interest). Our share of the costs to drill and complete this through December 31, 2014 was approximately $8,200.
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 $49.75 per bbl in December 2014 to a high of $103.75 per bbl in June 2014. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $2.74 per MMBtu in December 2014 to a high of $8.15 per MMBtu in February 2014. On December 31, 2013 the WTI posted price for crude oil was $49.75 per bbl and the Henry Hub spot price for natural gas was $3.14 per MMBtu.
Management is of the opinion that cash flow from operations and funds available from financing will be sufficient to provide adequate liquidity for the next fiscal year.
Contractual Obligations. We have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes our future payments we are obligated to make based on agreements in place as of December 31, 2014:
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Payments Due In:
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Total
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less than 1 year
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1-3 years
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3 years
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Contractual obligations:
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Secured bank line of credit (1)
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$
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5,750,000
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$
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—
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$
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5,750,000
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$
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—
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Leases (2)
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$
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33,719
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$
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23,442
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$
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10,277
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$
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—
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| (1) |
These amounts represent the balances outstanding under the bank line of credit. These repayments assume that interest will be paid on a monthly basis, no additional funds will be drawn and does not include estimated interest of $153,468 less than 1 year and $140,679 1-3 years. |
| (2) |
The lease amount represents the monthly rent amount for our principal office space in Midland, Texas under one three year lease agreement effective April 1, 2013 and a second three year lease agreement effective April 1, 2014. The total obligation for the remainder of the leases is $45,270 which includes $11,550 billed to and reimbursed by our majority shareholder for his portion of the shared office space. |
Results of Operations – Three Months Ended December 31, 2014 and 2013. For the quarter ended December 31, 2014, there was a net loss of $175,321 compared to net income of $88,659 for the quarter ended December 31, 2013. This was a result of a decrease in operating revenues, an increase in production costs and depreciation, depletion and amortization (“DD&A”) partially offset by an unrealized gain on derivatives.
Oil and gas sales. Revenue from oil and gas sales was $790,335 for the third quarter of fiscal 2015, a 17% decrease from $948,633 for the same period of fiscal 2014. This resulted from a decrease in oil and gas prices partially offset by an increase in oil and gas production.
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2014
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2013
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% Difference
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Oil:
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Revenue
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$
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465,325
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$
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629,765
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(26.1
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%)
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Volume (bbls)
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7,379
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6,808
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8.4
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%
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Average Price (per bbl)
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$
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63.06
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$
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92.51
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(31.8
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%)
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Gas:
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Revenue
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$
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325,010
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$
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318,868
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1.9
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%
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Volume (mcf)
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94,962
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89,059
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6.6
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%
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Average Price (per mcf)
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$
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3.42
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$
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3.58
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(4.5
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%)
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| (1) |
After giving effect to our derivative instruments, the average sales price per Bbl of oil was $66.49 for the quarter ended December 31, 2014 compared to $90.86 for the quarter ended December 31, 2013. |
Production and exploration. Production costs were $377,438 for the third quarter of fiscal 2015, a 29% increase from $291,828 for the same period of fiscal 2014. This was primarily the result of an increase in lease operating expenses as a result of recent acquisitions of working interests of non-operated properties.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was $353,158 for the third quarter of fiscal 2015, a 27% increase from $277,557 for the same period of fiscal 2014, primarily due to an increase to the full cost pool amortization base and an increase in oil and gas production.
General and administrative expenses. General and administrative expenses were $301,193 for the third quarter of fiscal 2015, a 9% increase from $275,489 for the same period of fiscal 2014. This was primarily due to an increase in stock option compensation, salary and insurance expenses.
Interest expense. Interest expense was $29,077 for the third quarter of fiscal 2015, an 89% increase from $15,353 for the same period of fiscal 2014, due to an increase in borrowings.
Derivatives. For the quarter ended December 31, 2014, we recorded derivative gains of $80,120 reflecting $25,281 of realized gains and $54,839 of unrealized gains resulting from our oil swap agreement. For the quarter ended December 31, 2013, we recorded derivative gains of $7,404 from our oil swap agreement ($11,190 of realized losses and $18,594 of unrealized gains).
Income taxes. There was an income tax benefit of $13,856, or (7%), for the quarter ended December 31, 2014 compared to an expense of $9,474, or 10%, for the quarter ended December 31, 2013. 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, 2014 and 2013. For the nine months ended December 31, 2014, there was a net loss of $70,011, a decrease from net income of $298,841 for the nine months ended December 31, 2013. This was a result of a decrease in operating revenues, an increase in production costs and depreciation, depletion and amortization (“DD&A”) partially offset by an unrealized gain on derivatives.
Oil and gas sales. Revenue from oil and gas sales was $2,784,932 for the nine months ended December 31, 2014, an 8% decrease from $3,041,004 for the same period of fiscal 2014. This resulted from a decrease in oil price and gas production partially offset by an increase in gas price and oil production.
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2014
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2013
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% Difference
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Oil:
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Revenue
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$
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1,741,229
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$
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2,018,523
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(13.7
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%)
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Volume (bbls)
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21,716
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20,947
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3.7
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%
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Average Price (per bbl)
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$
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80.18
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$
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96.36
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(16.8
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%)
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Gas:
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Revenue
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$
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1,043,703
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$
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1,022,481
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2.1
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%
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Volume (mcf)
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273,467
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281,643
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(2.9
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%)
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Average Price (per mcf)
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$
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3.82
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$
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3.63
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5.2
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%
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| (1) |
After giving effect to our derivative instruments, the average sales price per Bbl of oil was $79.95 for the nine months ended December 31, 2014 compared to $94.39 for the nine months ended December 31, 2013. |
Production and exploration. Production costs were $1,014,786 for the nine months ended December 31, 2014, an 11% increase from $913,418 for the nine months ended December 31, 2013. This was primarily the result of an increase in lease operating expenses as a result of recent acquisitions of working interests of non-operated properties.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was $976,669 for the nine months ended December 31, 2014, a 12% increase from $871,079 for the nine months ended December 31, 2013, primarily due to 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 $943,525 for the nine months ended December 31, 2014, an 8% increase from $873,573 for the nine months ended December 31, 2013. This was primarily due to an increase in accounting, salary and insurance expenses.
Interest expense. Interest expense was $60,623 for the nine months ended December 31, 2014, a 13% increase from $53,685 for the nine months ended December 31, 2013 due to an increase in borrowings.
Derivatives. For the nine months ended December 31, 2014, we recorded derivative gains of $97,871 reflecting $4,959 of realized losses and $102,830 of unrealized gains resulting from our oil swap agreement. For the nine months ended December 31, 2013, we recorded derivative losses of $79,284 from our oil swap agreement ($41,261 of realized losses and $38,023 of unrealized losses).
Income taxes. There was an income tax benefit of $21,759, or (24%), for the nine months ended December 31, 2014 compared to an income tax benefit of $42,783, or (17%), for the nine months ended December 31, 2013. 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.
Commodity Price Risk. 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 reported crude oil pricing on the 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. 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. As of April 1, 2013 and expiring on March 31, 2015, Mexco entered into a 24 month swap agreement with Merrill Lynch Commodities, Inc. for 500 bbls of crude oil per month at a fixed price of $90 per bbl.
At December 31, 2014, we had a net asset derivative position of $57,849 related to our price swap derivatives. Utilizing actual derivative contractual volumes as of December 31, 2014, a 10% increase or decrease in forward curves associated with the underlying commodity would have changed the net asset of these instruments by approximately $8,000. 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. If the settle oil price in any month during our agreement period is ten dollars per barrel more or less than the fixed price of $90.00 per bbl, the effect to Mexco would be $5,000 for that month.
Interest Rate Risk. At December 31, 2014, we had an outstanding loan balance of $5,750,000 under our $6.3 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 $57,500 based on the outstanding balance at December 31, 2014.
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, 2014, our largest credit risk associated with any single purchaser was $64,057 or 13% 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, 2014, our largest credit risk associated with any working interest partner was $13,482 or 26% 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. 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 ten dollars per barrel for the first nine months of fiscal 2015, our net income would have changed by $217,160. If the average gas price had increased or decreased by one dollar per mcf for the first nine months of fiscal 2015, our net income would have changed by $273,467.
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, 2014, our disclosure controls and procedures were effective.
Changes in Internal Control over Financial Reporting. No changes in our internal control over financial reporting occurred during the nine months ended December 31, 2014 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 2014 Annual Report on Form 10-K.
| 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
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31.1 |
Certification of the Chief Executive Officer of Mexco Energy Corporation |
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31.2 |
Certification of the Chief Financial Officer of Mexco Energy Corporation |
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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.
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MEXCO ENERGY CORPORATION
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(Registrant)
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Dated: February 13, 2015
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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 13, 2015
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/s/ Tamala L. McComic
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Tamala L. McComic
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President, Chief Financial Officer, Treasurer and Assistant Secretary
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