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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

 

x Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the period ended June 30, 2012

 

¨ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from             to            

Commission File Number 001-31759

 

 

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

 

 

 

OKLAHOMA   73-1055775

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

Grand Centre, Suite 300, 5400 N Grand Blvd., Oklahoma City, Oklahoma 73112
(Address of principal executive offices)

(405) 948-1560

Registrant’s telephone number including area code

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  x  Yes    ¨  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x  Yes    ¨  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   ¨    Accelerated filer   x
Non-accelerated filer   ¨    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨  Yes    x  No

Outstanding shares of Class A Common stock (voting) at August 7, 2012: 8,239,532

 

 

 


Table of Contents

INDEX

 

     Page  

Part I    Financial Information

  

Item 1    Condensed Financial Statements

  

Condensed Balance Sheets—June 30, 2012 and September 30, 2011

     1   

Condensed Statements of Operations—Three months and nine months ended June 30, 2012 and 2011

     2   

Statements of Stockholders’ Equity—Nine months ended June 30, 2012 and 2011

     3   

Condensed Statements of Cash Flows—Nine months ended June 30, 2012 and 2011

     4   

Notes to Condensed Financial Statements

     5   

Item 2     Management’s discussion and analysis of financial condition and results of operations

     12   

Item 3    Quantitative and qualitative disclosures about market risk

     18   

Item 4    Controls and procedures

     18   

Part II    Other Information

     19   

Item 2    Unregistered Sales of Equity Securities and Use of Proceeds

     19   

Item 6    Exhibits and reports on Form 8-K

     19   

Signatures

     19   


Table of Contents

The following defined terms are used in this report:

Bbl” means barrel;

“Board” means board of directors;

“CEGT” means Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma;

“DD&A” means depreciation, depletion and amortization;

“ESOP” refers to the Panhandle Oil and Gas Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan;

“FASB” means the Financial Accounting Standards Board;

“G&A” means general and administrative costs;

“Independent Consulting Petroleum Engineer(s)” or “Independent Consulting Petroleum Engineering Firm” refers to DeGolyer and MacNaughton of Dallas, Texas;

“LOE” means lease operating expense;

Mcf” means thousand cubic feet;

Mcfe” means natural gas stated on an Mcf basis and crude oil and natural gas liquids converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil or natural gas liquids to six Mcf of natural gas;

minerals”, “mineral acres” or “mineral interests” refers to fee mineral acreage owned in perpetuity by the Company;

“NGL” means natural gas liquids;

“NYMEX” refers to the New York Mercantile Exchange;

“PEPL” means Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline;

“play” is a term applied to identified areas with potential oil and/or natural gas reserves;

SEC” means the United States Securities and Exchange Commission;

working interest” refers to well interests in which the Company pays a share of the costs to drill, complete and operate a well and receives a proportionate share of production.

Fiscal year references

All references to years in this report, unless otherwise noted, refer to the Company’s fiscal year end of September 30. For example, references to 2012 mean the fiscal year ended September 30, 2012.

References to natural gas

Excluding 2012 amounts, all references to natural gas reserves, production, sales and prices include associated natural gas liquids.

References to oil and natural gas properties inherently include natural gas liquids associated with such properties.


Table of Contents

PART 1 FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED BALANCE SHEETS

 

     June 30, 2012     September 30, 2011  
     (unaudited)        

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 479,674      $ 3,506,999   

Oil and natural gas sales receivables

     6,165,551        8,811,404   

Deferred income taxes

     31,900        —     

Refundable income taxes

     —          354,246   

Refundable production taxes

     587,768        223,672   

Derivative contracts

     169,472        269,329   

Other

     133,987        95,408   
  

 

 

   

 

 

 

Total current assets

     7,568,352        13,261,058   

Properties and equipment, at cost, based on successful efforts accounting:

    

Producing oil and natural gas properties

     265,518,051        230,554,198   

Non-producing oil and natural gas properties

     10,845,809        11,100,350   

Furniture and fixtures

     664,508        628,929   
  

 

 

   

 

 

 
     277,028,368        242,283,477   

Less accumulated depreciation, depletion and amortization

     (159,795,938     (146,147,514
  

 

 

   

 

 

 

Net properties and equipment

     117,232,430        96,135,963   

Investments

     908,245        667,504   

Refundable production taxes

     916,594        1,359,668   
  

 

 

   

 

 

 

Total assets

   $ 126,625,621      $ 111,424,193   
  

 

 

   

 

 

 

Liabilities and Stockholders’ Equity

    

Current liabilities:

    

Accounts payable

   $ 4,926,378      $ 4,899,593   

Deferred income taxes

     —          7,100   

Income taxes payable

     690,951        —     

Accrued liabilities and other

     1,229,837        1,040,269   
  

 

 

   

 

 

 

Total current liabilities

     6,847,166        5,946,962   

Long-term debt

     8,000,000        —     

Deferred income taxes

     26,077,907        24,777,650   

Asset retirement obligations

     1,971,477        1,843,875   

Derivative contracts

     —          53,389   

Stockholders’ equity:

    

Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at June 30, 2012, and September 30, 2011

     140,524        140,524   

Capital in excess of par value

     1,943,555        1,924,507   

Deferred directors’ compensation

     2,573,469        2,665,583   

Retained earnings

     85,219,018        79,771,563   
  

 

 

   

 

 

 
     89,876,566        84,502,177   

Less treasury stock, at cost; 191,970 shares at June 30, 2012, and 175,331 shares at September 30, 2011

     (6,147,495     (5,699,860
  

 

 

   

 

 

 

Total stockholders’ equity

     83,729,071        78,802,317   
  

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 126,625,621      $ 111,424,193   
  

 

 

   

 

 

 

(See accompanying notes)

 

(1)


Table of Contents

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

 

     Three Months Ended June 30,     Nine Months Ended June 30,  
     2012      2011     2012      2011  
     (unaudited)     (unaudited)  

Revenues:

          

Oil and natural gas (and associated natural gas liquids) sales

   $ 8,438,709       $ 11,190,482      $ 29,748,884       $ 31,829,991   

Lease bonuses and rentals

     5,014,238         83,485        6,936,156         225,340   

Gains (losses) on derivative contracts

     81,164         344,856        449,997         332,183   

Income from partnerships

     115,581         69,594        355,898         179,910   
  

 

 

    

 

 

   

 

 

    

 

 

 
     13,649,692         11,688,417        37,490,935         32,567,424   

Costs and expenses:

          

Lease operating expenses

     2,254,543         2,212,181        6,570,942         6,491,630   

Production taxes

     289,642         268,425        1,071,993         1,035,497   

Exploration costs

     29,141         418,055        384,199         995,512   

Depreciation, depletion and amortization

     4,597,363         3,716,460        13,680,737         10,782,656   

Provision for impairment

     205,915         2,927        786,724         830,946   

Loss (gain) on asset sales, interest and other

     93,350         (44,279     45,846         (63,505

General and administrative

     1,498,439         1,423,219        4,802,119         4,529,157   
  

 

 

    

 

 

   

 

 

    

 

 

 
     8,968,393         7,996,988        27,342,560         24,601,893   
  

 

 

    

 

 

   

 

 

    

 

 

 

Income before provision for income taxes

     4,681,299         3,691,429        10,148,375         7,965,531   

Provision for income taxes

     1,581,000         1,041,000        2,960,000         2,116,000   
  

 

 

    

 

 

   

 

 

    

 

 

 

Net income

   $ 3,100,299       $ 2,650,429      $ 7,188,375       $ 5,849,531   
  

 

 

    

 

 

   

 

 

    

 

 

 

Basic and diluted earnings per common share (Note 3)

   $ 0.37       $ 0.32      $ 0.86       $ 0.70   
  

 

 

    

 

 

   

 

 

    

 

 

 

Basic and diluted weighted average shares outstanding:

          

Common shares

     8,249,954         8,256,252        8,253,079         8,279,784   

Unissued, directors' deferred compensation shares

     115,087         123,310        133,702         119,943   
  

 

 

    

 

 

   

 

 

    

 

 

 
     8,365,041         8,379,562        8,386,781         8,399,727   
  

 

 

    

 

 

   

 

 

    

 

 

 

Dividends declared per share of common stock and paid in period

   $ 0.07       $ 0.07      $ 0.21       $ 0.21   
  

 

 

    

 

 

   

 

 

    

 

 

 

(See accompanying notes)

 

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Table of Contents

PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Nine months Ended June 30, 2012

 

     Class A voting      Capital in     Deferred                          
     Common Stock      Excess of     Directors'     Retained     Treasury     Treasury        
     Shares      Amount      Par Value     Compensation     Earnings     Shares     Stock     Total  

Balances at September 30, 2011

     8,431,502       $ 140,524       $ 1,924,507      $ 2,665,583      $ 79,771,563        (175,331   $ (5,699,860   $ 78,802,317   

Purchase of treasury stock

     —           —           —          —          —          (38,771     (1,158,957     (1,158,957

Restricted stock awards

     —           —           239,858        —          —          —          —          239,858   

Net income

     —           —           —          —          7,188,375        —          —          7,188,375   

Dividends ($.21 per share)

     —           —           —          —          (1,740,920     —          —          (1,740,920

Distribution of deferred directors’ compensation

     —           —           (220,810     (406,769     —          22,132        711,322        83,743   

Increase in deferred directors’ compensation charged to expense

     —           —           —          314,655        —          —          —          314,655   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balances at June 30, 2012 (unaudited)

     8,431,502       $ 140,524       $ 1,943,555      $ 2,573,469      $ 85,219,018        (191,970   $ (6,147,495   $ 83,729,071   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Nine Months Ended June 30, 2011

 

     Class A voting      Capital in      Deferred                           
     Common Stock      Excess of      Directors’      Retained     Treasury     Treasury        
     Shares      Amount      Par Value      Compensation      Earnings     Shares     Stock     Total  

Balances at September 30, 2010

     8,431,502       $ 140,524       $ 1,816,365       $ 2,222,127       $ 73,599,733        (120,560   $ (4,196,753   $ 73,581,996   

Purchase of treasury stock

     —           —           —           —           —          (65,481     (1,851,290     (1,851,290

Restricted stock awards

     —           —           105,664         —           —          —          —          105,664   

Net income

     —           —           —           —           5,849,531        —          —          5,849,531   

Dividends ($.21 per share)

     —           —           —           —           (1,743,075     —          —          (1,743,075

Increase in deferred directors’ compensation charged to expense

     —           —           —           330,332         —          —          —          330,332   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balances at June 30, 2011 (unaudited)

     8,431,502       $ 140,524       $ 1,922,029       $ 2,552,459       $ 77,706,189        (186,041   $ (6,048,043   $ 76,273,158   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

(See accompanying notes)

 

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Table of Contents

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

 

     Nine months ended June 30,  
     2012     2011  
     (unaudited)  

Operating Activities

    

Net income

   $ 7,188,375      $ 5,849,531   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation, depletion and amortization

     13,680,737        10,782,656   

Impairment

     786,724        830,946   

Provision for deferred income taxes

     1,261,257        1,348,000   

Exploration costs

     384,199        995,512   

Net (gain) loss on sale of assets and lease bonuses

     (7,049,445     (223,587

Income from partnerships

     (355,898     (179,910

Distributions received from partnerships

     436,489        278,865   

Directors’ deferred compensation expense

     314,655        330,332   

Restricted stock awards

     239,858        105,664   

Cash provided by changes in assets and liabilities:

    

Oil and natural gas sales receivables

     2,645,853        653,278   

Fair value of derivative contracts

     46,468        1,348,877   

Refundable production taxes

     78,978        (40,806

Other current assets

     13,727        334,933   

Accounts payable

     374,076        36,593   

Income taxes receivable

     354,246        (878,860

Other non-current assets

     308        —     

Income taxes payable

     690,951        (922,136

Accrued liabilities

     (104,279     41,801   
  

 

 

   

 

 

 

Total adjustments

     13,798,904        14,842,158   
  

 

 

   

 

 

 

Net cash provided by operating activities

     20,987,279        20,691,689   

Investing Activities

    

Capital expenditures, including dry hole costs

     (16,026,416     (17,059,135

Acquisition of working interest properties

     (17,399,052     —     

Acquisition of minerals and overrides

     (2,625,569     (299,755

Proceeds from leasing of fee mineral acreage

     7,042,364        256,583   

Investments in partnerships

     (321,640     29,912   

Proceeds from sales of assets

     131,843        938   

Excess tax benefit on stock-based compensation

     83,743        —     
  

 

 

   

 

 

 

Net cash used in investing activities

     (29,114,727     (17,071,457

Financing Activities

    

Borrowings under debt agreement

     33,385,738        —     

Payments of loan principal

     (25,385,738     —     

Purchase of treasury stock

     (1,158,957     (1,851,290

Payments of dividends

     (1,740,920     (1,743,075
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     5,100,123        (3,594,365
  

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

     (3,027,325     25,867   

Cash and cash equivalents at beginning of period

     3,506,999        5,597,258   
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 479,674      $ 5,623,125   
  

 

 

   

 

 

 

Supplemental Schedule of Noncash Investing and Financing Activities

    

Additions to asset retirement obligations

   $ 45,702      $ 20,569   
  

 

 

   

 

 

 

Gross additions to properties and equipment

   $ 35,945,287      $ 17,818,134   

Net (increase) decrease in accounts payable for properties and equipment additions

     105,750        (459,244
  

 

 

   

 

 

 

Capital expenditures and acquisitions, including dry hole costs

   $ 36,051,037      $ 17,358,890   
  

 

 

   

 

 

 

(See accompanying notes)

 

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Table of Contents

PANHANDLE OIL AND GAS INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Accounting Principles and Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. (the Company) have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission (SEC). Management of the Company believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full year. The Company’s fiscal year runs from October 1 through September 30.

Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s 2011 Annual Report on Form 10-K.

NOTE 2: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits.

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume or income, reduce estimated taxable income or add to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with the detail well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion benefits, when a provision for income taxes is recorded, decrease the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded. The benefits of federal and Oklahoma excess percentage depletion are not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the nine months ended June 30, 2012, was 29% as compared to 27% for the nine months ended June 30, 2011. The effective tax rate for the quarter ended June 30, 2012, was 34% as compared to 28% for the quarter ended June 30, 2011. This increase is the result of an increase in the estimated annual effective tax rate during the third quarter due to higher expected fiscal 2012 income before provision for income taxes (mostly related to higher lease bonus income) projected as of June 30, 2012, as compared to projections as of March 31, 2012.

NOTE 3: Basic and Diluted Earnings per Share

Basic and diluted earnings per share is calculated using net income divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ deferred compensation shares during the period.

NOTE 4: Long-term Debt

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan in the amount of $80,000,000 which is subject to a semi-annual borrowing base determination, wherein BOK applies their own current pricing forecast and a 9% discount rate to the Company’s proved reserves as calculated by the Company’s Independent Consulting Petroleum Engineering Firm. When applying the discount rate, BOK also applies an advance rate percentage to certain proved non-producing and proved undeveloped reserves. The facility has a borrowing base of $35,000,000 and is secured by certain of the Company’s properties with a carrying value of $25,145,548 at June 30, 2012. The facility matures on November 30, 2014. The interest rate is based on national prime plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. The election of national prime or LIBOR is at the Company’s discretion. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and natural gas properties is advanced. The interest rate spread from national prime or LIBOR will be charged based on the percent of the value advanced of the calculated loan value of the Company’s oil and natural gas properties. At June 30, 2012, the effective interest rate was 2.25%.

The Company’s debt is recorded at the carrying amount on its balance sheet. The carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates.

 

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Table of Contents

Since the bank charges a customary non-use fee of .25% annually of the unused portion of the borrowing base, the Company has not requested the bank to increase its borrowing base beyond $35,000,000. Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and natural gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and may limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At June 30, 2012, the Company was in compliance with the covenants of the BOK agreement.

NOTE 5: Deferred Compensation Plan for Directors

The Company has a deferred compensation plan for non-employee directors (the Plan). The Plan provides that each eligible director can individually elect to receive shares of Company stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These shares are unissued and are credited to each director’s deferred fee account at the closing market price of the stock on the date earned. Upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan will be issued to the director.

NOTE 6: Restricted Stock Plan

On March 11, 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 100,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. The 2010 Stock Plan is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.

Effective March 2010, the board of directors approved the purchase of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

 

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2012 and 2011, related to the Company’s performance based and non-performance based restricted stock.

 

                                                                               
     Three Months Ended      Nine Months Ended  
     June 30,      June 30,  
     2012      2011      2012      2011  

Performance based, restricted stock

   $ 43,031       $ 14,303       $ 107,449       $ 28,606   

Non-performance based, restricted stock

     48,034         32,515         132,409         77,058   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total compensation expense

   $ 91,065       $ 46,818       $ 239,858       $ 105,664   

 

A summary of the Company’s unrecognized compensation cost for its unvested performance based and non-performance based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

 

     As of June 30, 2012  
     Unrecognized
Compensation Cost
     Weighted Average
Period (in years)
 

Performance based, restricted stock

   $ 366,008         2.14   

Non-performance based, restricted stock

     418,621         2.29   
  

 

 

    

Total

   $ 784,629      

Upon vesting, shares are expected to be issued out of shares held in treasury.

NOTE 7: Oil and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, natural gas and NGL reserves to be the most significant of its judgments and estimates. Changes in crude oil, natural gas and NGL reserve estimates affect the Company’s calculation of DD&A, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, natural gas and NGL reserves based on available geological and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available

 

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sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing prices current with the period. The estimated oil, natural gas and NGL reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, natural gas and NGL price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. Crude oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. However, projected future crude oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of crude oil, natural gas and NGL reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.

NOTE 8: Impairment

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates, future sales prices for oil, natural gas and NGL, future production costs, estimates of future oil, natural gas and NGL reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, natural gas and NGL reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing updated estimates of future prices. For the three months ended June 30, 2012 and 2011, the assessments resulted in $205,915 and $2,927 of impairment, respectively. For the nine months ended June 30, 2012 and 2011, the assessments resulted in $786,724 and $830,946 of impairment, respectively. A reduction in oil, natural gas or NGL prices or a decline in reserve volumes could lead to additional impairment that may be material to the Company.

NOTE 9: Capitalized Costs

At June 30, 2012 and 2011, non-producing oil and natural gas properties include costs of $188,449 and $1,751,766, respectively, on exploratory wells which were drilling and/or testing. On those wells drilling and/or testing as of June 30, 2012, the Company expects to have evaluation results within the next six months.

NOTE 10: Exploration Costs

In the quarter and nine month period ended June 30, 2012, lease expirations and leasehold impairments of $14,916 and $314,277, respectively, were charged to exploration costs. Leasehold impairments are recorded for individually insignificant non-producing leases which the Company believes will not be transferred to proved properties over the remaining lives of the leases. In the quarter and nine month period ended June 30, 2012, the Company also incurred costs of $14,225 and $69,922, respectively, related to exploratory dry holes. In the quarter and nine month period ended June 30, 2011, lease expirations and impairments of $305,156 and $455,486, respectively, were charged to exploration costs as well as costs of $112,899 and $540,026, respectively, related to exploratory dry holes.

NOTE 11: Derivatives

The Company has entered into fixed swap contracts, basis protection swaps and costless collar contracts. These derivative instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. Basis protection swaps guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL currently). The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays the counterparty if the price differential is less than the agreed terms of the contract. Collar contracts set a fixed floor price and a fixed ceiling price and provide for payments to the Company if the basis adjusted price falls below the floor or require payments by the Company if the basis adjusted price rises above the ceiling. These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices. These derivative instruments may expose the Company to risk of financial loss and limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are unsecured. The derivative instruments have settled or will settle based on the prices below which are adjusted for location differentials and tied to certain pipelines in Oklahoma.

 

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Derivative contracts in place as of June 30, 2012

(prices below reflect the Company’s net price from the listed Oklahoma pipelines)

 

Contract period

  

Production volume

covered per month

  

Indexed (1)

pipeline

  

Fixed price

Natural gas basis protection swaps

        

January - December 2012

   50,000 Mmbtu    CEGT    NYMEX - $.29

January - December 2012

   40,000 Mmbtu    CEGT    NYMEX - $.30

January - December 2012

   50,000 Mmbtu    PEPL    NYMEX - $.29

January - December 2012

   50,000 Mmbtu    PEPL    NYMEX - $.30

Natural gas costless collars

        

March - October 2012

   50,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.25 ceiling

April - October 2012

   120,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.10 ceiling

April - October 2012

   60,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.20 ceiling

April - October 2012

   50,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.20 ceiling

April - October 2012

   50,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.45 ceiling

April - October 2012

   50,000 Mmbtu    NYMEX Henry Hub    $2.50 floor/$3.30 ceiling

Oil costless collars

        

January - December 2012

   2,000 Bbls    NYMEX WTI    $90 floor/$105 ceiling

February - December 2012

   3,000 Bbls    NYMEX WTI    $90 floor/$110 ceiling

May - December 2012

   2,000 Bbls    NYMEX WTI    $90 floor/$114 ceiling

 

(1) CEGT - Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL - Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

 

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Derivative contracts in place as of September 30, 2011

(prices below reflect the Company’s net price from the listed Oklahoma pipelines)

 

Contract period

  

Production volume

covered per month

  

Indexed (1)

pipeline

  

Fixed price

Natural gas fixed price swaps

        

April - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.65

April - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.65

April - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.70

April - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.75

May - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.50

May - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.60

June - October 2011

   50,000 Mmbtu    NYMEX Henry Hub    $4.63

Natural gas basis protection swaps

        

January - December 2011

   50,000 Mmbtu    CEGT    NYMEX - $.27

January - December 2011

   50,000 Mmbtu    CEGT    NYMEX - $.27

January - December 2011

   50,000 Mmbtu    PEPL    NYMEX - $.26

January - December 2011

   50,000 Mmbtu    PEPL    NYMEX - $.27

January - December 2011

   70,000 Mmbtu    PEPL    NYMEX - $.36

January - December 2012

   50,000 Mmbtu    CEGT    NYMEX - $.29

January - December 2012

   40,000 Mmbtu    CEGT    NYMEX - $.30

January - December 2012

   50,000 Mmbtu    PEPL    NYMEX - $.29

January - December 2012

   50,000 Mmbtu    PEPL    NYMEX - $.30

Oil costless collars

        

April - December 2011

   5,000 Bbls    NYMEX WTI    $100 floor/$112 ceiling

 

(1) CEGT - Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL - Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

While the Company believes that its derivative contracts are effective in achieving the risk management objective for which they were intended, the Company has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was an asset of $169,472 as of June 30, 2012, and a net asset of $215,940 as of September 30, 2011. Realized and unrealized gains and (losses) for the periods ended June 30, 2012, and June 30, 2011, are scheduled below:

 

Gains (losses) on    Three months ended      Nine months ended  

derivative contracts

   6/30/2012     6/30/2011      6/30/2012     6/30/2011  

Realized

   $ 221,350      $ 195,210       $ 496,465      $ 1,681,060   

Increase (decrease) in fair value

     (140,186     149,646         (46,468     (1,348,877
  

 

 

   

 

 

    

 

 

   

 

 

 

Total

   $ 81,164      $ 344,856       $ 449,997      $ 332,183   
  

 

 

   

 

 

    

 

 

   

 

 

 

To the extent that a legal right of offset exists, the Company nets the fair value of its derivative contracts with the same counterparty in the accompanying balance sheets. The following table summarizes the Company’s derivative contracts as of June 30, 2012, and September 30, 2011:

 

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Balance Sheet

Location

   6/30/2012
Fair Value
     9/30/2011
Fair Value
 

Asset Derivatives:

        

Derivatives not designated as Hedging Instruments:

        

Commodity contracts

   Short-term derivative contracts    $ 169,472       $ 269,329   

Commodity contracts

   Long-term derivative contracts      —           —     
     

 

 

    

 

 

 

Total Asset Derivatives (a)

      $ 169,472       $ 269,329   
     

 

 

    

 

 

 

Liability Derivatives:

        

Derivatives not designated as Hedging Instruments:

        

Commodity contracts

   Short-term derivative contracts    $ —         $ —     

Commodity contracts

   Long-term derivative contracts      —           53,389   
     

 

 

    

 

 

 

Total Liability Derivatives (a)

      $ —         $ 53,389   
     

 

 

    

 

 

 

 

(a) See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

The fair value of derivative assets and derivative liabilities is adjusted for credit risk. The impact of credit risk was immaterial for all periods presented.

NOTE 12: Fair Value Measurements

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.

 

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2012.

 

     Quoted Prices
in Active
Markets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs
(Level 3)
     Total Fair
Value
 

Financial Assets (Liabilities):

          

Derivative Contracts—Swaps

   $ —         $ (193,252   $ —         $ (193,252

Derivative Contracts—Collars

   $ —         $ —        $ 362,724       $ 362,724   

Level 2—Market Approach—The fair values of the Company’s natural gas swaps are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas curves, or can be corroborated from active markets. These values are based upon, among other things, future prices and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.

Level 3—The fair values of the Company’s oil and natural gas collar contracts are based on a pricing model which utilizes inputs that are unobservable or not readily available in the public market. These values are based upon, among other things, crude oil and natural gas future prices, volatility and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.

 

A reconciliation of the Company’s assets classified as Level 3 measurements is presented below. All gains and losses are presented on the Gains (losses) on derivative contracts line item on our Statement of Operations.

 

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     Derivatives  

Balance of Level 3 as of October 1, 2011

   $ 293,847   

Total gains or (losses)—realized and unrealized:

  

Included in earnings

  

Realized

     482,125   

Unrealized

     (413,248

Included in other comprehensive income (loss)

     —     

Purchases, issuances and settlements

     —     

Transfers in and out of Level 3

     —     
  

 

 

 

Balance of Level 3 as of June 30, 2012

   $ 362,724   
  

 

 

 

 

The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.

 

     Quarter Ended June 30,  
     2012     2011  
     Fair Value      Impairment     Fair Value      Impairment  

Producing Properties

   $ 378,864       $ 205,915 (a)    $ 8,155       $ 2,927 (a) 
     Nine Months Ended June 30,  
     2012     2011  
     Fair Value      Impairment     Fair Value      Impairment  

Producing Properties

   $ 1,287,827       $ 786,724 (a)    $ 1,049,898       $ 830,946 (a) 

(a) At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil and natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.

The carrying amounts reported in the balance sheets for cash and cash equivalents, receivables, refundable income taxes, accounts payable and accrued liabilities approximate their fair values due to the short maturity of these instruments. The fair value of Company’s debt approximates its carrying amount as the interest rates on the Company’s revolving line of credit are approximately equivalent to market rates for similar type debt based on the Company’s credit worthiness, which represents level 3 of the fair value hierarchy.

NOTE 13: Acquisitions

On October 25, 2011, the Company closed an acquisition of certain Fayetteville Shale assets located in Van Buren, Conway and Cleburne Counties, Arkansas, in the core of the Fayetteville Shale. The Company acquired an average working interest of 2.3% in 193 producing non-operated natural gas wells and 1,531 acres of leasehold from a private seller. There were approximately 240 future infill drilling locations identified on the leasehold at the time of purchase. The purchase price was $17.4 million and was funded by utilizing cash on hand and $13.3 million from the Company’s bank credit facility. The purchase price was allocated to the producing wells based on fair value determined by estimated reserves. The purchase price allocation is preliminary, pending the finalization of asset valuations and working capital adjustments. Adjustments to the estimated fair values may be recorded during the allocation period, not to exceed one year from the date of acquisition.

Actual and Pro Forma Impact of Acquisitions (Unaudited)

Revenues attributable to this acquisition included in the Company’s statement of operations for the quarter and nine months ended June 30, 2012, were $718,740 and $2,655,150, respectively. Net income (loss) attributable to the acquisition included in the statement of operations for the quarter and nine months ended June 30, 2012, was ($96,349) and $349,598, respectively.

 

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The following table presents the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2010:

 

     For the Nine Months Ended  
     June 30  
     2012      2011  

Revenue:

     

As reported

   $ 37,490,935       $ 32,567,424   

Pro forma revenue

     409,988         3,293,040   
  

 

 

    

 

 

 

Pro forma

   $ 37,900,923       $ 35,860,464   

Net Income:

     

As reported

   $ 7,188,375       $ 5,849,531   

Pro forma income

     136,315         731,559   
  

 

 

    

 

 

 

Pro forma

   $ 7,324,690       $ 6,581,090   

The unaudited pro forma financial information is for informational purposes only and does not purport to present what our results would actually have been had this transaction actually occurred on the date presented or to project our results of operations or financial position for any future period.

NOTE 14: Recently Adopted Accounting Pronouncements

 

In December 2011, the Financial Accounting Standards Board issued “Balance Sheet: Disclosures about Offsetting Assets and Liabilities.” The new standard requires entities to disclose information about financial instruments and derivative instruments that are either offset on the balance sheet or are subject to a master netting arrangement, including providing both gross information and net information for recognized assets and liabilities, the net amounts presented on an entity's balance sheet and a description of the rights of offset associated with these assets and liabilities. The new standard is applicable for all entities that have financial instruments and derivative instruments shown using a net presentation on an entity's balance sheet or are subject to a master netting arrangement. The new standard is effective for interim and annual reporting periods for fiscal years beginning on or after January 1, 2013, and should be applied retrospectively for all periods presented. The Company plans to adopt this new standard effective January 1, 2013, and will provide any additional disclosures necessary to comply with the new standard.

In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. This update required certain additional disclosures related to fair value measurements. This update was adopted in our second quarter ended March 31, 2012. The adoption of this update did not materially impact our financial statement disclosures.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

 

ITEM 2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

Forward-Looking Statements for fiscal 2012 and later periods are made in this document. Such statements represent estimates by management based on the Company’s historical operating trends, its proved oil, natural gas and NGL reserves and other information currently available to management. The Company cautions that the Forward-Looking Statements provided herein are subject to all the risks and uncertainties incident to the acquisition, development and marketing of, and exploration for oil, natural gas and NGL reserves. Investors should also read the other information in this Form 10-Q and the Company’s 2011 Annual Report on Form 10-K where risk factors are presented and further discussed. For all the above reasons, actual results may vary materially from the Forward-Looking Statements and there is no assurance that the assumptions used are necessarily the most likely to occur.

LIQUIDITY AND CAPITAL RESOURCES

The Company had positive working capital of $721,186 at June 30, 2012, compared to $7,314,096 at September 30, 2011.

 

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Liquidity:

Cash and cash equivalents were $479,674 as of June 30, 2012, compared to $3,506,999 at September 30, 2011, a decrease of $3,027,325. Cash flows for the nine months ended June 30 are summarized as follows:

Net cash provided (used) by:

 

     2012     2011     Change  

Operating activities

   $ 20,987,279      $ 20,691,689      $ 295,590   

Investing activities

     (29,114,727     (17,071,457     (12,043,270

Financing activities

     5,100,123        (3,594,365     8,694,488   
  

 

 

   

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

   $ (3,027,325   $ 25,867      $ (3,053,192

Operating activities:

Net cash provided by operating activities increased $295,590 during the first nine months of 2012, explained as follows:

Collections of oil and natural gas sales and other receivables were higher for the 2012 period, compared to the 2011 period, resulting in increased cash provided by operating activities of $317,692.

Realized gains on derivative contracts decreased $1,184,595 in the 2012 period, as compared to the 2011 period.

In the first nine months of fiscal 2012, payments for field related LOE were $757,948 higher than in the first nine months of fiscal 2011.

Interest payments during the 2012 period increased $100,269, as compared to the 2011 period.

The Company had lower income tax payments of $1,997,973 during the nine months ended June 30, 2012, as compared to the nine months ended June 30, 2011.

Investing activities:

Net cash used in investing activities increased $12,043,270 during the 2012 period, the result of the following:

Capital expenditures for drilling activity decreased $1,032,719 from $17,059,135 in the 2011 period to $16,026,416 in the 2012 period.

The Company acquired producing properties, leasehold and mineral acreage in Arkansas and Oklahoma totaling $20,024,621 during the nine months ended June 30, 2012, as compared to $299,755 during the nine months ended June 30, 2011.

Lease bonus payments received increased $6,785,781 during the 2012 period, as compared to the 2011 period. In December 2011, the Company leased 2,431 net mineral acres in the horizontal Mississippian play in northern Oklahoma and received $1,713,717 in lease bonus payments. In April 2012, lease bonus payments of $4,800,461 were received by the Company as a result of leasing partial rights on 2,743 of its net mineral acres in Roger Mills County, Oklahoma.

Financing activities:

Net cash of $5,100,123 was provided by financing activities in the first nine months of 2012, as compared to net cash used in financing activities of $3,594,365 in the first nine months of 2011. The net cash provided increase of $8,694,488 is explained as follows:

The Company financed the acquisition of producing properties and leasehold in Arkansas discussed above utilizing its credit facility with Bank of Oklahoma and cash. As of June 30, 2012 and 2011, cash provided by financing activities through net borrowings was $8,000,000 and $0, respectively.

 

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Treasury stock purchases in the 2012 period totaled $1,158,957, as compared to $1,851,290 in the 2011 period, resulting in a $692,333 decrease of cash used.

Capital Resources:

Although capital expenditures for drilling decreased approximately $1 million (six percent) from 2011 to 2012, drilling activity in the Arkansas Fayetteville Shale and western Oklahoma has continued at a relatively steady pace. A significant portion of the Fayetteville Shale drilling continued to be on the acreage acquired during the 2012 first quarter. Drilling in western Oklahoma continues to be very active where the Company owns substantial mineral and leasehold acreage in oil and natural gas liquids-rich areas including the Anadarko (Cana) Woodford Shale, Horizontal Granite Wash, Hogshooter Wash, Cleveland, Tonkawa and Marmaton. Fiscal 2012 capital expenditures for drilling projects are expected to approximate $22 million, while asset acquisitions for fiscal 2012 are expected to approximate $20 million, totaling approximately $42 million. Although there may be decreases in oil, natural gas and NGL production from quarter to quarter (depending on the timing of new wells coming on line), we expect these capital outlays to result in an overall continued trend of production increases. We will continue to evaluate opportunities to acquire additional production or acreage which are expected to yield favorable returns on investment.

Since the Company is not the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of future participation in drilling and completing new wells and associated capital expenditures.

In April 2012, a transaction was completed in which the Company leased partial rights on its mineral acres located in Roger Mills County, Oklahoma, to a large independent exploration and production company. The lease term is three years and the Company received an upfront cash bonus and retained a three-sixteenths non-cost bearing royalty interest in all production from future wells drilled on these leased rights. After post closing adjustments, the net mineral acres leased totaled 2,743 and the cash bonus received was $4,800,461. The rights leased were from the surface to 100 feet below the base of the Virgilian (the base of the Virgilian is equivalent to the base of the Tonkawa). The Company retained the rights to deeper formations including the Granite Wash, Hogshooter Wash, Cleveland and Marmaton which are expected to yield better and more predictable well results. This transaction does not include any of the Company’s existing production or current proved oil, natural gas or NGL reserves. The Company retained its perpetual mineral ownership in the acreage. Panhandle routinely weighs the value of leasing our mineral rights against participation with a working interest in drilling opportunities, whether it be well-by-well or on a broader scope, to determine the optimum method to maximize the value of Panhandle’s assets.

Production of oil, natural gas and NGL increased 21% on an Mcfe basis during 2012, as compared to 2011. The Company first reported NGL production in the first quarter of 2012. Increased drilling activity over the last 12–18 months in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL production and reserves for the Company, necessitating the inclusion of NGL production beginning with the first quarter of 2012. The inclusion of NGL in the reserve calculation began with the 2011 year-end reserve report. In previous quarters and reserve calculations, all NGL sales revenues were included with natural gas sales revenues. Excluding the effect of the inclusion of NGL production during the nine months ended June 30, 2012, production volumes increased 15% on an Mcfe basis. This increase was due to production added from the newly acquired wells and from wells that have recently come on line, which has exceeded the natural production decline of pre-existing wells. Looking forward, we expect 2012 production to continue to exceed 2011 production due to these newly acquired wells and all wells that come on line throughout fiscal 2012.

Natural gas prices continued to decline through May 2012 to below $2.00 per Mmbtu, but have rebounded to the mid-to-upper $2.00 per Mmbtu range through June 2012. Natural gas storage levels are still above the five year range, but have been gradually converging toward the five year average. The high levels of natural gas in storage have resulted in announced cutbacks in domestic drilling activity and restricted natural gas production has been announced on existing wells by some operators. Natural gas futures prices indicate price improvement to the mid $3.00 per Mmbtu level through the remainder of calendar 2012. As of June 30, 2012, the Company had costless collar contracts covering 7,000 barrels per month of oil production through December 2012 and 380,000 Mmbtu per month of natural gas production through October 2012 and basis protection swap contracts covering 190,000 Mmbtu per month of natural gas production through December 2012. With continued highly volatile oil and natural gas prices, management continues to evaluate opportunities for product price protection by hedging a portion of the Company’s future oil and natural gas production.

Through the first three quarters of 2012, cash provided by operating activities of $20,987,279 more than funded capital expenditures for drilling and equipping wells of $16,026,416. After payment of our regular $.07 per share quarterly dividends totaling $1,740,920, treasury stock purchases of $1,158,957 and other miscellaneous investing activities, cash was reduced during 2012 by $3,027,325. During the first nine months of 2012, the Company utilized excess cash and the bank credit facility to finance approximately $20 million in asset purchases. Net borrowings on the credit facility at June 30, 2012, were $8,000,000.

 

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Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and equipping of wells, treasury stock purchases and dividend payments primarily from cash flow and cash on hand. As management evaluates opportunities to acquire additional assets, additional borrowings utilizing our bank credit facility could be necessary. Also, during times of oil, natural gas and NGL price decreases, or increased expenditures for drilling, it may be necessary to utilize the credit facility further in order to fund these expenditures. The Company has availability ($27,000,000 at June 30, 2012) under its revolving credit facility and is in compliance with its debt covenants (current ratio, debt to EBITDA, tangible net worth and dividends as a percent of operating cash flow). While the Company believes the availability could be increased (if needed) by placing more of the Company’s properties as security under the revolving credit facility, increases are at the discretion of the bank.

Based on expected capital expenditure levels and anticipated cash flows for 2012, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund additional acquisitions.

RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2012 – COMPARED TO THREE MONTHS ENDED JUNE 30, 2011

Overview:

The Company recorded a third quarter 2012 net income of $3,100,299, or $.37 per share, compared to a net income of $2,650,429, or $.32 per share, in the 2011 quarter. The increase in net income was principally due to increased lease bonuses, higher oil and natural gas sales volumes and decreased exploration costs, partially offset by lower oil and natural gas prices, increased DD&A and impairment expenses and lower gains on derivative contracts. These items are further discussed below.

Oil and Natural Gas (and associated natural gas liquids) Sales:

Oil and natural gas sales decreased $2,751,773 or 25% for the 2012 quarter. The decrease was due to lower natural gas sales prices of 56% and decreased oil sales prices of 8%, offset by increased oil volumes of 53% and increased natural gas volumes of 15%. The following table outlines the Company’s sales volumes and average sales prices for oil, natural gas and NGL for the three month periods of fiscal 2012 and 2011:

 

                                                                                                                                       
     Oil Bbls
Sold
     Average
Price
     Mcf
Sold
     Average
Price
     NGL Bbls
Sold
     Average
Price
     Mcfe
Sold
     Average
Price
 

Three months ended

                       

6/30/2012

     38,937       $ 88.41         2,273,649       $ 1.95         23,680       $ 23.29         2,649,351       $ 3.19   

6/30/2011

     25,382       $ 96.18         1,976,868       $ 4.43         *         *         2,129,160       $ 5.26   

The oil production increase is due to continued drilling in western Oklahoma oily plays such as the horizontal Granite Wash, Hogshooter Wash, Cleveland, Tonkawa and Marmaton. The natural gas production increase is mainly a result of production attributable to the acquisition in the Fayetteville Shale in Arkansas that the Company completed effective October 25, 2011.

Production for the last five quarters was as follows:

 

Quarter ended

   Oil Bbls Sold      Mcf Sold      NGL Bbls Sold      Mcfe Sold  

6/30/2012

     38,937         2,273,649         23,680         2,649,351   

3/31/2012

     30,614         2,303,797         27,834         2,654,485   

12/31/2011

     38,040         2,243,312         14,662         2,559,524   

9/30/2011

     27,418         2,268,606         *         2,433,114   

6/30/2011

     25,382         1,976,868         *         2,129,160   

 

* The Company reported NGL reserves for the first time in its 2011 year-end reserve report. Increased drilling activity over the last 12-18 months in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL reserves and production for the Company. These reserve and production increases necessitated inclusion of NGL in the 2011 year-end reserve calculation and 2012 production volumes. In quarters prior to 2012, all NGL sales revenues were included with natural gas sales revenues.

 

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Lease Bonuses and Rentals:

Lease bonuses and rentals increased $4,930,753 in the 2012 quarter as compared to the 2011 quarter. The increase was mainly due to the Company leasing 2,743 (after post close adjustments) net mineral acres in Roger Mills County, Oklahoma, for $4.8 million (after post close adjustments). The rights leased were from the surface to 100 feet below the base of the Virgilian (commonly referred to as the Tonkawa).

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was an asset of $169,472 as of June 30, 2012, and $271,449 as of June 30, 2011. The Company had a net gain on derivative contracts of $81,164 in the 2012 quarter as compared to a net gain of $344,856 recorded in the 2011 quarter. The decrease in gains is mostly due to the natural gas fixed price swaps, which expired in October 2011, being profitable in the 2011 period, as natural gas prices were below the fixed prices.

Exploration Costs:

Exploration costs decreased $388,914 in the 2012 quarter as compared to the 2011 quarter. During the 2012 quarter, leasehold impairment and expired leasehold totaled $14,916 compared to $305,156 during the 2011 quarter, a $290,240 decrease. Charges on unsuccessful prospect costs totaled $14,225 during the 2012 quarter; whereas, in the 2011 quarter $112,899 was charged on two exploratory dry holes.

Depreciation, Depletion and Amortization (DD&A):

DD&A increased $880,903 or 24% in the 2012 quarter. DD&A in the 2012 quarter was $1.74 per Mcfe as compared to $1.75 per Mcfe in the 2011 quarter. DD&A increased $907,996 due to oil and natural gas production volumes increasing 24% in the 2012 quarter.

Provision for Impairment:

The provision for impairment increased $202,988 in the 2012 quarter compared to the 2011 quarter. During the 2011 quarter, impairment of $2,927 was recorded on one field in Oklahoma. During the 2012 quarter, impairment of $205,915 was recorded on three small fields in Oklahoma. These fields have few wells and are more susceptible to impairment when a well in the field experiences downward reserve revisions.

Income Taxes:

Provision for income taxes was $540,000 higher in the 2012 quarter than the 2011 quarter. Income before provision for income taxes increased from $3,691,429 in the 2011 quarter to $4,681,299 in the 2012 quarter and the effective tax rate increased to 34% in the 2012 quarter from 28% in the 2011 quarter. This increase is the result of an increase in the estimated annual effective tax rate during the third quarter due to higher expected fiscal 2012 income before provision for income taxes (mostly related to higher lease bonus income) projected as of June 30, 2012, as compared to projections as of March 31, 2012. The increased income before provision for income taxes and the increased effective tax rate resulted in the increase in provision for income taxes.

NINE MONTHS ENDED JUNE 30, 2012 – COMPARED TO NINE MONTHS ENDED JUNE 30, 2011

Overview:

The Company recorded a nine month period 2012 net income of $7,188,375, or $.86 per share, as compared to a net income of $5,849,531, or $.70 per share, in the 2011 period. Major contributing factors to the increase in net income were increased lease bonuses, higher oil and natural gas sales volumes and decreased exploration costs, partially offset by increased DD&A expense and lower natural gas prices. These items are further discussed below.

Oil and Natural Gas (and associated natural gas liquids) Sales:

Oil and natural gas sales decreased $2,081,107 as a result of lower natural gas sales prices of 38%, partially offset by increased oil volumes of 40%, increased natural gas volumes of 13% and increasing oil sales prices of 4%. The table below outlines the Company’s sales volumes and average sales prices for oil, natural gas and NGL for the nine month periods of fiscal 2012 and 2011:

 

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Table of Contents
                                                                                                               
     Oil Bbls
Sold
     Average
Price
     Mcf
Sold
     Average
Price
     NGL Bbls
Sold
     Average
Price
     Mcfe
Sold
     Average
Price
 

Nine months ended

                       

6/30/2012

     107,591       $ 91.36         6,820,758       $ 2.59         66,176       $ 33.58         7,863,360       $ 3.78   

6/30/2011

     76,723       $ 88.10         6,029,051       $ 4.16         *         *         6,489,389       $ 4.90   

 

* The Company reported NGL reserves for the first time in its 2011 year-end reserve report. Increased drilling activity over the last 12-18 months in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL reserves and production for the Company. These reserve and production increases necessitated inclusion of NGL in the 2011 year-end reserve calculation and 2012 production volumes. In quarters prior to 2012, all NGL sales revenues were included with natural gas sales revenues.

The oil production increase is due to continued drilling in western Oklahoma oily plays such as the horizontal Granite Wash, Hogshooter Wash, Cleveland, Tonkawa and Marmaton. The natural gas production increase is mainly a result of production attributable to the acquisition in the Fayetteville Shale in Arkansas that the Company completed effective October 25, 2011. The Company owns a substantial mineral acreage position in western Oklahoma and drilling in these plays is expected to continue at a rapid pace throughout fiscal 2012 giving the Company the opportunity to continue to increase its oil production. Drilling for natural gas in the Fayetteville Shale play both on legacy acreage and the recently acquired acreage remains brisk. Although there may be decreases in oil, natural gas and NGL production from quarter to quarter (depending on the timing of new wells coming on line), we expect an overall continued trend of production increases.

Lease Bonuses and Rentals:

Lease bonuses and rentals increased $6,710,816 in the 2012 period. The increase was mainly due to the Company leasing 2,743 (after post close adjustments) net mineral acres in Roger Mills County, Oklahoma, for $4.8 million (after post close adjustments). The rights leased were from the surface to 100 feet below the base of the Virgilian (commonly referred to as the Tonkawa). The Company also leased 2,431 net acres in the horizontal Mississippian play in northern Oklahoma for $1.7 million.

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was an asset of $169,472 as of June 30, 2012, and $271,449 as of June 30, 2011. The Company had a net gain of $449,997 in the nine months ended June 30, 2012, compared to a gain of $332,183 for the nine months ended June 30, 2011. The Company received net cash payments (realized gains) of $496,465 and $1,681,060 for the 2012 and 2011 periods, respectively.

Exploration Costs:

Exploration costs decreased $611,313 in the 2012 period compared to the 2011 period. Charges on two exploratory dry holes and unsuccessful prospect costs totaled $69,922 during the 2012 period; whereas, in the 2011 period, the Company had two exploratory dry holes totaling $540,026. The decrease in dry hole costs was coupled with a decrease in leasehold impairment and expired leasehold. During the 2012 period, leasehold impairment and expired leasehold totaled $314,277 compared to $455,486 during the 2011 period, a $141,209 decrease.

Depreciation, Depletion and Amortization (DD&A):

DD&A increased $2,898,081 or 27% in the 2012 period. DD&A was $1.74 per Mcfe in the 2012 period compared to $1.66 per Mcfe in the 2011 period. DD&A increased $2,282,060 due to oil and natural gas production volumes increasing 21% in the 2012 period compared to the 2011 period. The remaining increase of $616,021 was caused by an $.08 increase in the DD&A rate. This rate increase is due to higher finding cost experienced in oil and liquids rich areas where the Company is drilling and has had new wells come on line.

General and Administrative Costs (G&A):

G&A costs increased $272,962 or 6% in the 2012 period. The increase is primarily related to increases in personnel expenses of $161,519 and legal expenses of $114,747. The increase in personnel expense is due to compensation and employee insurance increases. The increase in legal expense is a result of more significant acquisition and mineral lease activity.

 

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Income Taxes:

The fiscal 2012 period provision for income taxes of $2,960,000 was a result of a pre-tax income of $10,148,375 as compared to a provision for income taxes of $2,116,000 in the fiscal 2011 period resulting from a pre-tax income of $7,965,531. The effective tax rate was 29% and 27% for the 2012 and 2011 periods, respectively. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both the 2012 and the 2011 periods.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Critical accounting policies are those the Company believes are most important to portraying its financial conditions and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. There have been no material changes to the critical accounting policies previously disclosed in the Company’s Form 10-K for the fiscal year ended September 30, 2011.

 

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of natural gas and oil price trends, and there remains a rather wide divergence in the opinions held by some in the industry. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in oil or natural gas liquids prices. Longer term natural gas prices will be determined by the supply of and demand for natural gas as well as the prices of competing fuels, such as crude oil and coal. The market price of natural gas, oil and natural gas liquids in 2012 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures and production. Excluding the impact of the Company’s 2012 derivative contracts, based on the Company’s estimated natural gas volumes for 2012, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,005,000 for operating revenue. Based on the Company’s estimated oil volumes for 2012, the price sensitivity in 2012 for each $1.00 per barrel change in wellhead oil price is approximately $112,000 for operating revenue.

Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. As of June 30, 2012, the Company has basis protection swaps and oil and natural gas collars in place. All of our outstanding derivative contracts are with one counterparty and are unsecured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas and oil prices. These derivative contracts may expose the Company to risk of financial loss and limit the benefit of future increases in prices. For the Company’s basis protection swaps, a change of $.10 in the basis differential from NYMEX and the indexed pipelines would result in a change to pre-tax operating income of approximately $113,000. For the Company’s natural gas collars, a change of $.10 in the forward strip prices would result in a change to pre-tax operating income of approximately $65,000. For the Company’s oil collars, a change of $1.00 in the forward strip prices would result in a change to pre-tax operating income of approximately $36,000.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facilities. The revolving loan bears interest at the national prime rate plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. At June 30, 2012, the Company had $8,000,000 outstanding under these facilities. At this point, the Company does not believe that its liquidity has been materially affected by the debt market uncertainties noted in the last few years and the Company does not believe that its liquidity will be impacted in the near future.

 

ITEM 4 CONTROLS AND PROCEDURES

The Company maintains “disclosure controls and procedures,” as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including the Company’s President/Chief Executive Officer and Vice President/Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. The Company’s disclosure controls and

 

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procedures have been designed to meet, and management believes that they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this report, the Chief Executive Officer and Chief Financial Officer have concluded that, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective to ensure that material information relating to the Company is made known to them. There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting made during the fiscal quarter or subsequent to the date the assessment was completed.

PART II OTHER INFORMATION

 

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the three months ended June 30, 2012, the Company did not repurchase shares of the Company’s common stock.

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the Board of Directors approved repurchase of up to $1.5 million of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. Pursuant to previously adopted board resolutions, the purchase of an additional $1.5 million of the Company’s common stock became authorized and approved effective March 14, 2012. As of June 30, 2012, the approximate dollar value of shares that may yet be purchased under the program was $1,200,000. The shares are held in treasury and are accounted for using the cost method.

 

ITEM 6 EXHIBITS AND REPORT ON FORM 8-K

 

  (a) EXHIBITS – Exhibit 31.1 and 31.2 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002

  Exhibit 32.1 and 32.2 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002

  Exhibit 101.INS – XBRL Instance Document

  Exhibit 101.SCH – XBRL Taxonomy Extension Schema Document

  Exhibit 101.CAL – XBRL Taxonomy Extension Calculation Linkbase Document

  Exhibit 101.LAB – XBRL Taxonomy Extension Labels Linkbase Document

  Exhibit 101.PRE – XBRL Taxonomy Extension Presentation Linkbase Document

  Exhibit 101.DEF – XBRL Taxonomy Extension Definition Linkbase Document

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.

 

    PANHANDLE OIL AND GAS INC.
August 7, 2012     /s/ Michael C. Coffman
Date    

Michael C. Coffman, President and

Chief Executive Officer

August 7, 2012     /s/ Lonnie J. Lowry
Date    

Lonnie J. Lowry, Vice President

and Chief Financial Officer

August 7, 2012     /s/ Robb P. Winfield
Date    

Robb P. Winfield, Controller

and Chief Accounting Officer

 

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