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PHX MINERALS INC. - Quarter Report: 2013 June (Form 10-Q)

phx20130627_10q.htm

 

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, 2013                                                                       .                                                                            

 

(   )           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)

 

Registrant's telephone number including area code    (405) 948-1560 .                                               

 

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, 2013: 8,220,347

 

 
 

 

 

INDEX

  

   

Page 

Part I 

Financial Information 

 
       
 

Item 1

Condensed Financial Statements  
       
   

Condensed Balance Sheets – June 30, 2013 and September 30, 2012

1 

       
   

Condensed Statements of Operations – Three months and nine months ended June 30, 2013 and 2012

2  

       
   

Statements of Stockholders’ Equity – Nine months ended June 30, 2013 and 2012

3 

       
   

Condensed Statements of Cash Flows – Nine months ended June 30, 2013 and 2012

4  

       
   

Notes to Condensed Financial Statements 

5 

       
 

Item 2 

Management's discussion and analysis of financial condition and results of operations

11 

       
 

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 

 

 
 

 

 

The following defined terms are used in this report:

 

“Bbl” means barrel;

 

“Board” means board of directors;

 

“BTU” means British Thermal Units;

 

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

 

“Company” refers to Panhandle Oil and Gas Inc.;

 

“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;

 

“Mmbtu” means million BTU;

 

“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;

 

“Panhandle” refers to Panhandle Oil and Gas Inc.;

 

“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;

 

royalty interest” refers to well interests in which the Company does not pay a share of the costs to drill, complete and operate a well, but receives a much smaller proportionate share (as compared to a working interest) of production;

 

“SEC” refers to 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;

 

“WTI” refers to West Texas Intermediate.

 

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 2013 mean the fiscal year ended September 30, 2013.

 

References to oil and natural gas properties

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

 

 
 

 

 

PART 1 FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED BALANCE SHEETS

 

   

June 30, 2013

   

September 30, 2012

 
   

(unaudited)

         

Assets

               

Current assets:

               

Cash and cash equivalents

  $ 1,381,705     $ 1,984,099  

Oil, NGL and natural gas sales receivables

    12,234,870       8,349,865  

Derivative contracts

    814,978       -  

Deferred income taxes

    55,900       121,900  

Refundable income taxes

    -       325,715  

Refundable production taxes

    620,590       585,454  

Other

    124,617       255,812  

Total current assets

    15,232,660       11,622,845  
                 

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

               

Producing oil and natural gas properties

    297,124,313       275,997,569  

Non-producing oil and natural gas properties

    9,504,728       10,150,561  

Furniture and fixtures

    720,565       668,004  
      307,349,606       286,816,134  

Less accumulated depreciation, depletion and amortization

    (181,919,478 )     (165,199,079 )

Net properties and equipment

    125,430,128       121,617,055  
                 

Investments

    1,509,609       1,034,870  

Refundable production taxes

    623,776       911,960  

Total assets

  $ 142,796,173     $ 135,186,730  
                 

Liabilities and Stockholders' Equity

               

Current liabilities:

               

Accounts payable

  $ 6,648,091     $ 6,447,692  

Derivative contracts

    -       172,271  

Accrued liabilities and other

    978,063       1,007,779  

Total current liabilities

    7,626,154       7,627,742  
                 

Long-term debt

    13,565,237       14,874,985  

Deferred income taxes

    29,293,907       26,708,907  

Asset retirement obligations

    2,332,949       2,122,950  
                 

Stockholders' equity:

               

Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at June 30, 2013, and September 30, 2012

    140,524       140,524  

Capital in excess of par value

    2,479,619       2,020,229  

Deferred directors' compensation

    2,667,765       2,676,160  

Retained earnings

    91,316,131       84,821,395  
      96,604,039       89,658,308  

Less treasury stock, at cost; 211,155 shares at June 30, 2013, and 181,310 shares at September 30, 2012

    (6,626,113 )     (5,806,162 )

Total stockholders' equity

    89,977,926       83,852,146  

Total liabilities and stockholders' equity

  $ 142,796,173     $ 135,186,730  

 

(See accompanying notes)

 

 
(1)

 

 

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

 

   

Three Months Ended June 30,

   

Nine Months Ended June 30,

 
   

2013

   

2012

   

2013

   

2012

 
   

(unaudited)

   

(unaudited)

 

Revenues:

                           

Oil, NGL and natural gas sales

  $ 15,827,137     $ 8,438,709     $ 42,686,935     $ 29,748,884  

Lease bonuses and rentals

    24,146       5,014,238       539,479       6,936,156  

Gains (losses) on derivative contracts

    1,714,832       81,164       796,166       449,997  

Income from partnerships

    164,330       115,581       470,286       355,898  
      17,730,445       13,649,692       44,492,866       37,490,935  

Costs and expenses:

                               

Lease operating expenses

    3,105,709       2,254,543       9,040,613       6,570,942  

Production taxes

    460,902       289,642       1,177,341       1,071,993  

Exploration costs

    25,648       29,141       60,827       384,199  

Depreciation, depletion and amortization

    5,192,544       4,597,363       17,090,187       13,680,737  

Provision for impairment

    7,400       205,915       225,841       786,724  

Loss (gain) on asset sales, interest and other

    29,789       93,350       (138,921 )     45,846  

General and administrative

    1,585,285       1,498,439       5,127,025       4,802,119  
      10,407,277       8,968,393       32,582,913       27,342,560  

Income before provision for income taxes

    7,323,168       4,681,299       11,909,953       10,148,375  
                                 

Provision for income taxes

    2,253,000       1,581,000       3,669,000       2,960,000  
                                 

Net income

  $ 5,070,168     $ 3,100,299     $ 8,240,953     $ 7,188,375  
                                 
                                 
                                 

Basic and diluted earnings per common share (Note 3)

  $ 0.61     $ 0.37     $ 0.99     $ 0.86  
                                 

Basic and diluted weighted average shares outstanding:

                               

Common shares

    8,163,520       8,249,954       8,247,642       8,253,079  

Unissued, directors' deferred compensation shares

    116,762       115,087       113,259       133,702  
      8,280,282       8,365,041       8,360,901       8,386,781  
                                 

Dividends declared per share of common stock and paid in period

  $ 0.07     $ 0.07     $ 0.21     $ 0.21  

 

(See accompanying notes)

  

 
(2)

 

 

PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

 

Nine months Ended June 30, 2013

 

   

Class A voting

Common Stock

   

Capital in

Excess of

   

Deferred

Directors'

   

Retained

   

Treasury

   

Treasury

         
   

Shares

   

Amount

   

Par Value

   

Compensation

   

Earnings

   

Shares

   

Stock

   

Total

 
                                                                 

Balances at September 30, 2012

    8,431,502     $ 140,524     $ 2,020,229     $ 2,676,160     $ 84,821,395       (181,310 )   $ (5,806,162 )   $ 83,852,146  
                                                                 

Purchase of treasury stock

    -       -       -       -       -       (42,206 )     (1,214,638 )     (1,214,638 )
                                                                 

Restricted stock awards

    -       -       541,937       -       -       -       -       541,937  
                                                                 

Net income

    -       -       -       -       8,240,953       -       -       8,240,953  
                                                                 

Dividends ($.21 per share)

    -       -       -       -       (1,746,217 )     -       -       (1,746,217 )
                                                                 

Distribution of deferred directors' compensation

    -       -       (82,547 )     (297,154 )     -       12,361       394,687       14,986  
                                                                 

Increase in deferred directors' compensation charged to expense

    -       -       -       288,759       -       -       -       288,759  
                                                                 

Balances at June 30, 2013 (unaudited)

    8,431,502     $ 140,524     $ 2,479,619     $ 2,667,765     $ 91,316,131       (211,155 )   $ (6,626,113 )   $ 89,977,926  

 

 

Nine Months Ended June 30, 2012

 

   

Class A voting

Common Stock

   

Capital in

Excess of

   

Deferred

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  

 

(See accompanying notes)

    

 
(3)

 

 

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

 

   

Nine months ended June 30,

 
   

2013

   

2012

 

Operating Activities

 

(unaudited)

 

Net income

  $ 8,240,953     $ 7,188,375  

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

               

Depreciation, depletion and amortization

    17,090,187       13,680,737  

Impairment

    225,841       786,724  

Provision for deferred income taxes

    2,651,000       1,261,257  

Exploration costs

    60,827       384,199  

Gain from leasing of fee mineral acreage

    (538,133 )     (6,929,651 )

Net gain on sale of assets

    (208,750 )     (119,794 )

Income from partnerships

    (470,286 )     (355,898 )

Distributions received from partnerships

    603,249       436,489  

Directors' deferred compensation expense

    288,745       314,655  

Restricted stock awards

    541,937       239,858  

Cash provided by changes in assets and liabilities:

               

Oil, NGL and natural gas sales receivables

    (3,885,005 )     2,645,853  

Fair value of derivative contracts

    (987,249 )     46,468  

Refundable production taxes

    253,048       78,978  

Other current assets

    78,889       13,727  

Accounts payable

    (48,038 )     374,076  

Income taxes receivable

    325,715       354,246  

Other non-current assets

    -       308  

Income taxes payable

    50,854       690,951  

Accrued liabilities

    (80,570 )     (104,279 )

Total adjustments

    15,952,261       13,798,904  

Net cash provided by operating activities

    24,193,214       20,987,279  
                 

Investing Activities

               

Capital expenditures, including dry hole costs

    (20,576,359 )     (16,026,416 )

Acquisition of working interest properties

    -       (17,399,052 )

Acquisition of minerals and overrides

    (783,750 )     (2,625,569 )

Proceeds from leasing of fee mineral acreage

    557,196       7,042,364  

Investments in partnerships

    (607,702 )     (321,640 )

Proceeds from sales of assets

    870,610       131,843  

Net cash used in investing activities

    (20,540,005 )     (29,198,470 )
                 

Financing Activities

               

Borrowings under debt agreement

    9,353,651       33,385,738  

Payments of loan principal

    (10,663,399 )     (25,385,738 )

Purchase of treasury stock

    (1,214,638 )     (1,158,957 )

Payments of dividends

    (1,746,217 )     (1,740,920 )

Excess tax benefit on stock-based compensation

    15,000       83,743  

Net cash provided by (used in) financing activities

    (4,255,603 )     5,183,866  
                 

Increase (decrease) in cash and cash equivalents

    (602,394 )     (3,027,325 )

Cash and cash equivalents at beginning of period

    1,984,099       3,506,999  

Cash and cash equivalents at end of period

  $ 1,381,705     $ 479,674  
                 

Supplemental Schedule of Noncash Investing and Financing Activities

               

Additions to asset retirement obligations

  $ 119,166     $ 45,702  
                 

Gross additions to properties and equipment

  $ 21,660,852     $ 35,945,287  

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

    (300,743 )     105,750  

Capital expenditures and acquisitions, including dry hole costs

  $ 21,360,109     $ 36,051,037  

 

(See accompanying notes)

 

 
(4)

 

 

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. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the 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 2012 Annual Report on Form 10-K.

 

Certain amounts (net gain on sales of assets in the Statements of Cash Flows) in the prior year have been reclassified to conform to the current year presentation.

 

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, 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, 2013, was 31% as compared to 29% for the nine months ended June 30, 2012. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for the nine month periods ended June 30, 2013, and June 30, 2012. The effective tax rate for the quarter ended June 30, 2013, was 31% as compared to 34% for the quarter ended June 30, 2012. The decreased rate was the result of an increase in the estimated annual effective tax rate during the 2012 third quarter resulting from higher projected income before provision for income taxes (mostly related to higher lease bonus income) at June 30, 2012, as compared to the projections made 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, plus 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 an 8% 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 all 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 $36,900,585 at June 30, 2013. 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, 2013, the effective interest rate was 2.43%.

 

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.

 

 
(5)

 

 

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. 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. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and 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, 2013, 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 be credited with future unissued shares of Company stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These unissued shares 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 unissued shares credited 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.

 

On December 11, 2012, the Company awarded 6,701 non-performance based shares and 20,104 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of three years and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $195,603 and $305,154, respectively, and will be recognized as compensation expense ratably over the vesting period. The fair value of the performance based shares on their award date is calculated by simulating the Company’s stock price and stock price return utilizing a Monte Carlo model covering the period from the grant date through the end of the performance period (December 11, 2012, through December 11, 2015).

 

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2013 and 2012, related to the Company’s performance based and non-performance based restricted stock.

 

   

Three Months Ended

June 30,

   

Nine Months Ended

June 30,

 
   

2013

   

2012

   

2013

   

2012

 

Performance based, restricted stock

  $ 81,822     $ 43,031     $ 263,583     $ 107,449  

Non-performance based, restricted stock

    60,208       48,034       278,354       132,409  

Total compensation expense

  $ 142,030     $ 91,065     $ 541,937     $ 239,858  

 

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, 2013

 
   

Unrecognized

Compensation Cost

   

Weighted Average

Period (in years)

 

Performance based, restricted stock

  $ 364,548       1.54  

Non-performance based, restricted stock

    287,836       1.62  

Total

  $ 652,384          

  

 
(6)

 

 

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


NOTE 7: Oil, NGL and Natural Gas Reserves

 

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


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, NGL and natural gas, future production costs, estimates of future oil, NGL and natural gas 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, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing updated projected future price decks current with the period. For the three months ended June 30, 2013 and 2012, the assessment resulted in provisions of $7,400 and $205,915, respectively. For the nine months ended June 30, 2013 and 2012, the assessment resulted in provisions of $225,841 and $786,724, respectively. A reduction in oil, NGL or natural gas prices, or a decline in reserve volumes, could lead to additional impairment that may be material to the Company.

 

NOTE 9: Capitalized Costs

 

As of June 30, 2013 and 2012, non-producing oil and natural gas properties include costs of $0 and $188,449, respectively, on exploratory wells which were drilling and/or testing.

 

NOTE 10: Exploration Costs

 

In the quarter and nine month period ended June 30, 2013, lease expirations and leasehold impairments of $25,345 and $53,961, 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, 2013, the Company also had additional costs of $303 and $6,866, respectively, related to exploratory dry holes. In the quarter and nine month period ended June 30, 2012, lease expirations and impairments of $14,916 and $314,277, respectively, were charged to exploration costs as well as additional costs of $14,225 and $69,922, 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 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 are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL historically). 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 expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are secured. The derivative instruments have settled or will settle based on the prices below which are adjusted for location differentials and tied to certain pipelines.

 

 
(7)

 

 

Derivative contracts in place as of June 30, 2013

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

 

Contract period

Production volume

covered per month

Indexed

pipeline

Fixed price

Natural gas costless collars

     

February 2013 - December 2013

80,000 Mmbtu

NYMEX Henry Hub

$3.75 floor/$4.25 ceiling

February 2013 - December 2013

50,000 Mmbtu

NYMEX Henry Hub

$3.75 floor/$4.30 ceiling

February 2013 - December 2013

100,000 Mmbtu

NYMEX Henry Hub

$3.75 floor/$4.05 ceiling

November 2013 - April 2014

160,000 Mmbtu

NYMEX Henry Hub

$4.00 floor/$4.55 ceiling

       

Natural gas fixed price swaps

     

March - October 2013

100,000 Mmbtu

NYMEX Henry Hub

$3.505

March - October 2013

70,000 Mmbtu

NYMEX Henry Hub

$3.400

April - December 2013

40,000 Mmbtu

NYMEX Henry Hub

$3.655

May - November 2013

100,000 Mmbtu

NYMEX Henry Hub

$4.320

       

Oil costless collars

     

March - December 2013

3,000 Bbls

NYMEX WTI

$90.00 floor/$102.00 ceiling

March - December 2013

4,000 Bbls

NYMEX WTI

$90.00 floor/$101.50 ceiling

May - December 2013

2,000 Bbls

NYMEX WTI

$90.00 floor/$97.50 ceiling

  

Derivative contracts in place as of September 30, 2012

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

 

Contract period

Production volume

covered per month

Indexed

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

August - October 2012

50,000 Mmbtu

NYMEX Henry Hub

$2.50 floor/$3.30 ceiling

November 2012 - January 2013

150,000 Mmbtu

NYMEX Henry Hub

$3.00 floor/$3.70 ceiling

November 2012 - January 2013

150,000 Mmbtu

NYMEX Henry Hub

$3.00 floor/$3.70 ceiling

November 2012 - January 2013

50,000 Mmbtu

NYMEX Henry Hub

$3.00 floor/$3.65 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

  

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 a net asset of $814,978 as of June 30, 2013, and a net liability of $172,271 as of September 30, 2012. Realized and unrealized gains and losses for the periods ended June 30, 2013, and June 30, 2012, are scheduled below:

 

 
(8)

 

  

Gains (losses) on

 

Three months ended

   

Nine months ended

 

derivative contracts

 

6/30/2013

   

6/30/2012

   

6/30/2013

   

6/30/2012

 

Realized

  $ (359,860 )   $ 221,350     $ (191,083 )   $ 496,465  

Increase (decrease) in fair value

    2,074,692       (140,186 )     987,249       (46,468 )

Total

  $ 1,714,832     $ 81,164     $ 796,166     $ 449,997  

  

The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Balance Sheets. The Company has chosen to present the fair values of its derivative contracts under master netting agreements using a net fair value presentation.


                 The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Condensed Balance Sheets at June 30, 2013, and September 30, 2012. The Company adopted the accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at June 30, 2013, and September 30, 2012.

 

   

6/30/2013

Fair Value (a)

Commodity Contracts

   

9/30/2012

Fair Value (a)

Commodity Contracts

 
   

Current Assets

   

Current Liabilities

   

Current Assets

   

Current Liabilities

 

Gross amounts recognized

  $ 928,299     $ 113,321     $ 51,530     $ 223,801  

Offsetting adjustments

    (113,321 )     (113,321 )     (51,530 )     (51,530 )

Net presentation on Condensed Balance Sheets

  $ 814,978     $ -     $ -     $ 172,271  

  

(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, 2013, and September 30, 2012.

 

As of June 30, 2013   

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

  $ -     $ 261,939     $ -     $ 261,939  

Derivative Contracts - Collars

  $ -     $ -     $ 553,039     $ 553,039  

  

 
(9)

 

 

As of September 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   $ -     $ (75,334 )   $ -     $ (75,334 )
Derivative Contracts - Collars   $ -     $ -     $ (96,937 )   $ (96,937 )

 

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 future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

 

Level 3 – The fair values of the Company’s costless 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 future prices, volatility, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

 

The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of oil and natural gas, market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase (decrease) in the forward prices and volatility of oil and natural gas prices will decrease (increase) the fair value of oil and natural gas derivatives, and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives.

 

The following table represents quantitative disclosures about unobservable inputs for Level 3 Fair Value Measurements.

 

Instrument Type

 

Unobservable Input

 

Range

 

Weighted

Average

   

Fair Value

June 30, 2013

 
                             

Oil Collars

 

Oil price volatility curve

  0%  - 15.22%   9.18%     $ (18,765 )

Natural Gas Collars

 

Natural gas price volatility curve

  0%  - 23.79%   16.19%     $ 571,804  

  

A reconciliation of the Company’s derivative contracts 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.

 

   

Derivatives

 

Balance of Level 3 as of October 1, 2012

  $ (96,937 )

Total gains or (losses) - realized and unrealized:

       

Included in earnings

       

Realized

    210,667  

Unrealized

    439,309  

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, 2013

  $ 553,039  

 

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,

 
   

2013

   

2012

 
   

Fair Value

   

Impairment

   

Fair Value

   

Impairment

 

Producing Properties

  $ 14,849     $ 7,400

(a)

  $ 378,864     $ 205,915

(a)

 

   

Nine Months Ended June 30,

 
   

2013

   

2012

 
   

Fair Value

   

Impairment

   

Fair Value

   

Impairment

 

Producing Properties

  $ 356,855     $ 225,841

(a)

  $ 1,287,827     $ 786,724

(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 net 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.

 

 
(10)

 

 

At June 30, 2013, and September 30, 2012, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future cash flows pursuant to the terms of the debt agreements and applies estimated current market interest rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

 

NOTE 13: 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 adopted this new standard effective January 1, 2013.

 

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.

 

NOTE 14: Subsequent Events

 

On July 26, 2013, the Company was notified and received a class action lawsuit settlement of approximately $604,000 related to the underpayment of royalty interest revenues. The settlement is a gain contingency and will be reflected in earnings in the fourth quarter of fiscal 2013.

 

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 2013 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, NGL and natural gas 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, NGL and natural gas reserves. Investors should also read the other information in this Form 10-Q and the Company’s 2012 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 $7,606,506 at June 30, 2013, compared to $3,995,103 at September 30, 2012.

 

Liquidity:

 

Cash and cash equivalents were $1,381,705 as of June 30, 2013, compared to $1,984,099 at September 30, 2012, a decrease of $602,394. Cash flows for the nine months ended June 30 are summarized as follows:

 

Net cash provided (used) by:

 

   

2013

   

2012

   

Change

 
                         

Operating activities

  $ 24,193,214     $ 20,987,279     $ 3,205,935  
                         

Investing activities

    (20,540,005 )     (29,198,470 )     8,658,465  
                         

Financing activities

    (4,255,603 )     5,183,866       (9,439,469 )
                         

Increase (decrease) in cash and cash equivalents

  $ (602,394 )   $ (3,027,325 )   $ 2,424,931  

  

Operating activities:


Net cash provided by operating activities increased $3,205,935 during the first nine months of 2013, the result of the following:

 

 
(11)

 

 

Higher receipts of oil, NGL and natural gas sales (net of production taxes and gathering, transportation and marketing costs) increased cash provided by operating activities from the 2012 period to the 2013 period by $4,593,241.

 

Cash flows from operating activities decreased $687,548 as net realized losses on derivative contracts were $191,083 in the 2013 period, compared to net realized gains on derivative contracts in the 2012 period of $496,465.

 

Field related LOE payments in the first nine months of 2013 exceeded payments during the same period in 2012 by $129,133, reducing cash provided by operating activities.

 

Payment of general and administrative expenses, debt interest and income taxes increased during 2013, compared to 2012, decreasing cash provided by operating activities by $354,590.

 

Investing activities:

 

Net cash used in investing activities decreased $8,658,465 during the first nine months of 2013, the result of the following:

 

Higher drilling and completion activity during the period ending June 30, 2013, as compared to the same period in 2012, increased capital expenditures by $4,549,943.

 

Cash used to acquire properties totaled $783,750 in the 2013 period and $20,024,621 in the 2012 period, a decrease of $19,240,871. In the 2012 first quarter the Company acquired producing properties, leasehold and mineral acreage in Arkansas totaling approximately $18.8 million.

 

Lease bonus payments received during the first nine months of 2013 were $557,196, compared to $7,042,364 during the first nine months of 2012, a decrease in cash provided by investing activities of $6,485,168. In the 2012 first quarter, the Company leased 2,431 net mineral acres in the horizontal Mississippi Limestone play in northern Oklahoma receiving lease bonus payments of approximately $1.7 million. In the third quarter of 2012, the Company received lease bonus payments of approximately $4.8 million, the result of leasing partial rights on 2,743 net mineral acres in Roger Mills County, Oklahoma.

 

Financing activities:

 

Net cash of $4,255,603 was used in financing activities in the first nine months of 2013, as compared to net cash provided by financing activities of $5,183,866 in the first nine months of 2012. The change of $9,439,469 of net cash provided is the result of the following:

 

The Company financed the first quarter 2012 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, cash provided by financing activities through net borrowings was $8,000,000. As of June 30, 2013, cash used in financing activities to reduce outstanding borrowings was $1,309,748. The combined effect is a decrease in cash provided by financing activities of $9,309,748.

 

Capital Resources:

 

Through the first nine months of 2013, as compared to the first nine months of 2012, capital expenditures to drill and complete wells increased $4,549,943 (28%). During the 2013 third quarter the Company experienced a significant increase in expenditures to drill and complete wells. Oil and NGL rich plays in western Oklahoma and the Texas Panhandle account for the majority of the drilling activity. Other active areas are the Arkansas Fayetteville Shale (dry natural gas), southern Oklahoma Woodford Shale (oil and NGL rich), Permian Basin of West Texas (oil and NGL rich) and Bakken Shale in North Dakota (oil).

 

Drilling continues to be active in the following oil and NGL rich plays where the Company owns mineral and leasehold acreage:

 

 

Horizontal Granite Wash and Hogshooter in western Oklahoma and the Texas Panhandle

 

 

Horizontal Cleveland in western Oklahoma and the Texas Panhandle

 

 

Horizontal Marmaton in western Oklahoma

 

 

Horizontal Tonkawa in western Oklahoma

 

 

Horizontal Anadarko Basin Woodford Shale in western Oklahoma

 

 

Horizontal Ardmore Basin Woodford Shale in southern Oklahoma

 

 
(12)

 

 

Capital expenditures for drilling and completion projects for the 2013 period were $20,576,359. In addition, mineral acreage in the Fayetteville Shale and the southeast Oklahoma Woodford Shale was acquired for $783,750. Panhandle has received a greater number of well proposals in recent months and has consequently increased the number of wells approved for participation with a working interest. We expect this increased activity to continue through the end of 2013, resulting in capital expenditures for drilling and completion projects of approximately $28 million. The shift of capital outlays more toward oil and NGL rich plays and less toward plays for dry natural gas, combined with production volumes from new wells in which the Company owns a non-cost-bearing royalty interest, is expected to result in continued increases in oil and NGL production volumes, with natural gas production leveling off in future quarters. As experienced previously, the timing of new wells coming on line may cause intermittent decreases in oil, NGL and natural gas production from quarter to quarter. Management continues to evaluate opportunities to acquire additional production or acreage.

 

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

 

The following table compares the Company’s 2013 production to that of 2012:

 

   

Nine months

   

Nine months

         
   

ended

   

ended

   

Percent

 
   

6/30/2013

   

6/30/2012

   

Change

 

Oil (Bbls)

    154,697       107,591       44%  

NGL (Bbls)

    81,524       66,176       23%  

Natural gas (Mcf)

    8,066,250       6,820,758       18%  

Total Mcfe

    9,483,576       7,863,360       21%  

 

These production increases are the result of new production coming on line which has exceeded the natural production decline of existing wells. We expect 2013 production to exceed that of 2012 as new production will continue to come on line through the remaining three months of 2013.

 

Product pricing for 2013 and 2012 is compared in the table below:

 

   

Nine months

   

Nine months

         
   

ended

   

ended

   

Percent

 
   

6/30/2013

   

6/30/2012

   

Change

 

Oil price per Bbl

  $ 86.73     $ 91.36       -5%  

NGL price per Bbl

  $ 27.22     $ 33.58       -19%  

Natural gas price per Mcf

  $ 3.35     $ 2.59       29%  

Price per Mcfe

  $ 4.50     $ 3.78       19%  

 

Panhandle’s oil sales price has averaged 93% of NYMEX oil price over the last 12 months. Based on this correlation, and NYMEX oil futures prices, we expect the Company’s average oil sales price for 2013 to approximate $90.00 per barrel. For the last 12 months, NGL sales prices averaged 30% of NYMEX oil price; this would correlate to an average NGL sales price for 2013 of approximately $28.00 per barrel, which is also in line with management’s expectations.

 

The extended winter experienced in many parts of the United States during March and April resulted in gas storage levels below the five-year average going into the natural gas storage injection season. Currently, gas storage levels have climbed to near the five-year average. As natural gas is used to generate electric power, abnormally hot or cool temperatures for the remainder of the injection season could affect natural gas prices going forward. For the previous 12 months, Panhandle’s natural gas sales price has averaged 93% of NYMEX natural gas price. Based on NYMEX natural gas futures prices, management expects the Company’s average natural gas sales price for 2013 to approximate $3.40 per Mcf.

 

As of June 30, 2013, the Company had the following derivative contracts in place:

 

Natural gas costless collar contracts

February 2013 – December 2013:

230,000 Mmbtu per month (floor and ceiling per Mmbtu of $3.75 and $4.05-$4.30, respectively)


November 2013 – April 2014:

160,000 Mmbtu per month (floor and ceiling per Mmbtu of $4.00 and $4.55, respectively)

 

 
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Natural gas fixed price swaps

March 2013 – October 2013:

170,000 Mmbtu per month (fixed price of $3.40-$3.505 per Mmbtu)

 

April 2013 – December 2013:

40,000 Mmbtu per month (fixed price of $3.655 per Mmbtu)

 

May 2013 – November 2013:

100,000 Mmbtu per month (fixed price of $4.32 per Mmbtu)

 

Oil costless collar contracts

March 2013 – December 2013:

7,000 Bbls per month (floor and ceiling per Bbl of $90.00 and $101.50-$102.00, respectively)

 

May 2013 – December 2013:

2,000 Bbls per month (floor and ceiling per Bbl of $90.00 and $97.50, respectively)

 

With continued oil and natural gas price volatility, management continues to evaluate opportunities for product price protection through additional hedging of the Company’s future oil and natural gas production.

 

The use of the Company’s cash provided by operating activities and resultant change to cash is summarized in the table below:

 

   

Nine months

 
   

ended

 
   

6/30/2013

 
         

Cash provided by operating activities

  $ 24,193,214  

Cash used for:

       

Capital expenditures - drilling and completion of wells

    20,576,359  

Quarterly dividends of $.07 per share

    1,746,217  

Treasury stock purchases

    1,214,638  

Net principal payments on credit facility

    1,309,748  

Other investing activities

    (51,354 )

Net cash used

    24,795,608  
         

Net increase (decrease) in cash

  $ (602,394 )

 

Outstanding borrowings on the credit facility at March 31, 2013, were $13,565,237.

 

Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and completion of wells, treasury stock purchases and dividend payments primarily from cash provided by operating activities 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, NGL and natural gas price decreases, or increased capital expenditures, it may be necessary to utilize the credit facility further in order to fund these expenditures. The Company has availability ($21,434,763 at June 30, 2013) 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 provided by operating activities for 2013, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund acquisitions.

 

RESULTS OF OPERATIONS

 

THREE MONTHS ENDED JUNE 30, 2013 – COMPARED TO THREE MONTHS ENDED JUNE 30, 2012

 

Overview:

 

The Company recorded third quarter 2013 net income of $5,070,168, or $.61 per share, compared to net income of $3,100,299, or $.37 per share, in the 2012 quarter. The increase in net income was principally the result of increased oil, NGL and natural gas sales; increased gains on derivative contracts; partially offset by decreased lease bonuses; and increased DD&A and lease operating expenses. These items are further discussed below.

 

 
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Oil, NGL and Natural Gas Sales:


Oil, NGL and natural gas sales increased $7,388,428 or 88% for the 2013 quarter. Oil, NGL and natural gas sales were up due to increases in oil, NGL and natural gas sales volumes of 42%, 8% and 21%, respectively, and increases in NGL and natural gas sales prices of 11% and 92%, respectively. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the three month periods of 2013 and 2012:

 

   

Oil Bbls

   

Average

   

Mcf

   

Average

   

NGL Bbls

   

Average

   

Mcfe

   

Average

 
   

Sold

   

Price

   

Sold

   

Price

   

Sold

   

Price

   

Sold

   

Price

 

Three months ended

                                                               

6/30/2013

    55,474     $ 88.02       2,742,996     $ 3.75       25,660     $ 25.79       3,229,800     $ 4.90  

6/30/2012

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

 

Oil and NGL production increases resulted from continued drilling in the western Oklahoma and Texas Panhandle horizontal oil plays, principally the Marmaton, Cleveland, Tonkawa, Hogshooter, and Granite Wash and to a lesser extent horizontal oil drilling in the Bakken in North Dakota and the Woodford Shale in southern Oklahoma (Anadarko and Ardmore Basins). The natural gas production increase was largely attributable to continued drilling in the Fayetteville Shale in Arkansas and natural gas produced from new wells in western Oklahoma. Panhandle owns substantial acreage positions in each of the plays previously mentioned in Oklahoma and the Texas Panhandle as well as the Arkansas Fayetteville and expects continued drilling on its acreage in these plays. Expected drilling activity in the fourth quarter of 2013 will provide the Company opportunities to further increase its oil and NGL production for fiscal 2013. We are anticipating that natural gas production will level off in the coming quarters as new volumes associated with both dry gas drilling and our oil and liquids rich drilling are anticipated to approximately offset the natural decline of production from our existing properties.

 

Production for the last five quarters was as follows:

 

Quarter ended

 

Oil Bbls Sold

   

Mcf Sold

   

NGL Bbls Sold

   

Mcfe Sold

 

6/30/2013

    55,474       2,742,996       25,660       3,229,800  

3/31/2013

    52,567       2,778,869       25,190       3,245,411  

12/31/2012

    46,656       2,544,385       30,674       3,008,365  

9/30/2012

    45,552       2,251,540       32,538       2,720,080  

6/30/2012

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

 

Lease Bonuses and Rentals:

 

Lease bonuses and rentals decreased $4,990,092 in the 2013 quarter as compared to the 2012 quarter. The decrease was mainly due to the Company leasing partial rights on 2,743 net mineral acres in Roger Mills County, Oklahoma, for $4.8 million in the 2012 quarter.

 

Gains (Losses) on Derivative Contracts:

 

At June 30, 2013, the Company’s fair value of derivative contracts was a net asset of $814,978; whereas at June 30, 2012, the Company’s fair value of derivative contracts was a net asset of $169,472. The Company had a net gain on derivative contracts of $1,714,832 in the 2013 quarter as compared to a net gain of $81,164 recorded in the 2012 quarter. The change was principally due to our natural gas fixed price swaps and collars increasing in value. Projected NYMEX natural gas prices are below both the fixed swap price and the floor of the collars at June 30, 2013.

 

Lease Operating Expenses (LOE):

 

LOE increased $851,166 or 38% in the 2013 quarter. LOE per Mcfe increased in the 2013 quarter to $.96 compared to $.85 in the 2012 quarter. LOE related to field operating costs increased $80,917 in the 2013 quarter compared to the 2012 quarter, a 7% increase. This increase was principally a result of production increasing 22%. Field operating costs were $.38 per Mcfe in the 2013 quarter as compared to $.43 per Mcfe in the 2012 quarter. The decrease in rate was due to fewer workovers in the 2013 quarter.

 

The increase in LOE related to field operating costs was coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) on natural gas of $770,249 in the 2013 quarter compared to the 2012 quarter. On a per Mcfe basis, these fees increased $.16 due to higher natural gas sales and the significant addition of natural gas wells in the Fayetteville Shale play in Arkansas, which have higher handling fees. Handling fees are charged either as a percent of natural gas sales or based on natural gas production volumes.

 

 
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Depreciation, Depletion and Amortization (DD&A):

 

DD&A increased $595,181 or 13% in the 2013 quarter. DD&A in the 2013 quarter was $1.61 per Mcfe as compared to $1.74 per Mcfe in the 2012 quarter. DD&A increased $1,007,241 due to production increasing 22% in the 2013 quarter compared to the 2012 quarter. The offsetting decrease of $412,060 was caused by a $.13 decrease in the DD&A rate. This rate decrease was mainly due to higher reserve prices at June 30, 2013, (compared to June 30, 2012) increasing ultimate reserves on a significant number of wells.

 

Provision for Impairment:

 

The provision for impairment decreased $198,515 in the 2013 quarter compared to the 2012 quarter. During the 2013 quarter, impairment of $7,400 was recorded on one small field. During the 2012 quarter, impairment of $205,915 was recorded on three small fields. These fields have few wells and are more susceptible to impairment when a well in these fields experiences downward reserve revisions due to reserve pricing or well performance.

 

Income Taxes:

 

The provision for income taxes was $672,000 higher in the 2013 quarter than the 2012 quarter. Income before provision for income taxes increased from $4,681,299 in the 2012 quarter to $7,323,168 in the 2013 quarter and the effective tax rate decreased to 31% in the 2013 quarter from 34% in the 2012 quarter. This decrease in the rate is the result of an increase in the estimated annual effective tax rate during the 2012 third quarter due to higher expected 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.

 

NINE MONTHS ENDED JUNE 30, 2013 – COMPARED TO NINE MONTHS ENDED JUNE 30, 2012

 

Overview:

 

The Company recorded nine month 2013 net income of $8,240,953, or $.99 per share, as compared to net income of $7,188,375, or $.86 per share, in the 2012 period. Major contributing factors to the increase in net income were higher oil, NGL and natural gas sales; decreased provision for impairment; decreased exploration costs; and increased gains on derivative contracts; partially offset by decreased lease bonuses; increased DD&A expenses; increased LOE; and increased G&A. These items are further discussed below.

 

Oil, NGL and Natural Gas Sales:


Oil, NGL and natural gas sales increased $12,938,051 as a result of increased oil, NGL and natural gas sales volumes of 44%, 23% and 18%, respectively, and increased natural gas sales prices of 29%, partially offset by lower oil and NGL sales prices of 5% and 19%, respectively. The table below outlines the Company’s sales volumes and average sales prices for oil, NGL and natural gas for the nine month periods of 2013 and 2012:

 

   

Oil Bbls

   

Average

   

Mcf

   

Average

   

NGL Bbls

   

Average

   

Mcfe

   

Average

 
   

Sold

   

Price

   

Sold

   

Price

   

Sold

   

Price

   

Sold

   

Price

 

Nine months ended

                                                               

6/30/2013

    154,697     $ 86.73       8,066,250     $ 3.35       81,524     $ 27.22       9,483,576     $ 4.50  

6/30/2012

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

 

Oil and NGL production increases resulted from continued drilling in the western Oklahoma and Texas Panhandle horizontal oil plays, principally the Marmaton, Cleveland, Tonkawa, Hogshooter, and Granite Wash and to a lesser extent horizontal oil drilling in the Bakken in North Dakota and the Woodford Shale in southern Oklahoma (Anadarko and Ardmore Basins). The natural gas production increase is largely attributable to continued drilling in the Fayetteville Shale in Arkansas and natural gas produced from new wells in western Oklahoma. Panhandle owns substantial acreage positions in each of the plays previously mentioned in Oklahoma and the Texas Panhandle as well as the Arkansas Fayetteville and expects continued drilling on its acreage in these plays. Expected drilling activity in the fourth quarter of 2013 will provide the Company opportunities to further increase its oil and NGL production for fiscal 2013. We are anticipating that natural gas production will level off in the coming quarters as new volumes associated with both dry gas drilling and our oil and liquids rich drilling are anticipated to approximately offset the natural decline of production from our existing properties.

 

Lease Bonuses and Rentals:

 

Lease bonuses and rentals decreased $6,396,677 in the 2013 period. The decrease was mainly due to the Company leasing partial rights on 2,743 net mineral acres in Roger Mills County, Oklahoma, for $4.8 million and leasing 2,431 net acres in the horizontal Mississippian play in northern Oklahoma for $1.7 million in the 2012 period.

 

 
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Gains (Losses) on Derivative Contracts:

 

The fair value of derivative contracts was a net asset of $814,978 as of June 30, 2013, as compared to a net asset of $169,472 at June 30, 2012. The Company had a net gain of $796,166 in the nine months ended June 30, 2013, compared to a net gain of $449,997 for the nine months ended June 30, 2012. The Company made net cash payments (realized losses) of $191,083 in the 2013 period and received net cash payments (realized gains) of $496,465 for the 2012 period.

 

Lease Operating Expenses (LOE):

 

LOE increased $2,469,671 or 38% in the 2013 period. LOE per Mcfe increased in the 2013 period to $.95 compared to $.84 in the 2012 period. LOE related to field operating costs increased $539,306 in the 2013 period compared to the 2012 period, a 16% increase. This increase is principally a result of production increasing 21%. The field operating costs for the 2013 and 2012 periods were $.41 per Mcfe and $.42 per Mcfe, respectively.

 

The increase in LOE related to field operating costs was coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) on natural gas of $1,930,365 in the 2013 period compared to the 2012 period. On a per Mcfe basis, these fees increased $.14 due to higher natural gas sales and the significant addition of new natural gas wells in the Fayetteville Shale play in Arkansas, which have higher handling fees. Handling fees are charged either as a percent of natural gas sales or based on natural gas production volumes.

 

Exploration Costs:

 

Exploration costs decreased $323,372 in the 2013 period as compared to the 2012 period. During the 2013 period, leasehold impairment and expired leasehold totaled $53,961 compared to $314,277 during the 2012 period, a $260,316 decrease. The decrease was due primarily to one leasehold prospect which was significantly impaired in the 2012 period. Charges on exploratory dry holes totaled $6,866 during the 2013 period as compared to $69,922 in the 2012 period.

 

Depreciation, Depletion and Amortization (DD&A):

 

DD&A increased $3,409,450 or 25% in the 2013 period. DD&A was $1.80 per Mcfe in the 2013 period as compared to $1.74 per Mcfe in the 2012 period. DD&A increased $2,818,865 due to production increasing 21% in the 2013 period as compared to the 2012 period. The remaining increase of $590,585 was the result of a $.06 increase in the DD&A rate. This rate increase is mainly due to lower reserve prices during the 2013 period as compared to the 2012 period and higher per Mcfe finding cost experienced in oil and liquids-rich areas where the Company is spending the majority of its capital.

 

Provision for Impairment:

 

The provision for impairment decreased $560,883 in the 2013 period compared to the 2012 period. During the 2012 period, impairment of $786,724 was recorded on ten small fields. During the 2013 period, impairment of $225,841 was recorded on four small fields. These fields have few wells and are more susceptible to impairment when a well in these fields experiences downward reserve revisions.

 

General and Administrative Costs (G&A):

 

G&A costs increased $324,906 or 7% in the 2013 period. This increase was primarily related to increases in personnel expenses of $338,778. Increases in personnel expenses were mainly due to restricted stock expense.

 

Income Taxes:

 

The 2013 period provision for income taxes was $3,669,000 on pre-tax income of $11,909,953 as compared to a provision for income taxes of $2,960,000 in the 2012 period on pre-tax income of $10,148,375. The effective tax rate was 31% and 29% for the 2013 and 2012 periods, respectively. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both the 2013 and the 2012 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, 2012.

 

 
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ITEM 3  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Market Risk

 

Oil, NGL and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of oil, NGL and natural gas 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 NGL 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 oil, NGL and natural gas in 2013 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 2013 derivative contracts, based on the Company’s estimated natural gas volumes for 2013, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,060,000 for operating revenue. Based on the Company’s estimated oil volumes for 2013, the price sensitivity in 2013 for each $1.00 per barrel change in wellhead oil price is approximately $213,000 for operating revenue. Based on the Company’s estimated NGL volumes for 2013, the price sensitivity in 2013 for each $1.00 per barrel change in NGL price is approximately $110,000 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. All of our outstanding derivative contracts are with one counterparty and are secured. 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 expose the Company to risk of financial loss and may limit the benefit of future increases in prices. As of June 30, 2013, the Company has natural gas fixed price swaps and oil and natural gas collars in place. For the Company’s fixed price swaps, a change of $.10 in the NYMEX Henry Hub forward strip prices would result in a change to pre-tax operating income of approximately $142,000. For the Company’s natural gas collars, a change of $.10 in the basis differential from NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $178,000. For the Company’s oil collars, a change of $1.00 in the basis differential from NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $30,000.

 

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, 2013, the Company had $13,565,237 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 procedures have been designed to meet, and management believes 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, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective to ensure 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.

 

 
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PART II OTHER INFORMATION

 

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

During the three months ended June 30, 2013, the Company repurchased shares of the Company’s common stock as summarized in the table below.

 

Period

 

Total Number of Shares Purchased

   

Average Price Paid per Share

   

Total Number of Shares Purchased as Part of Publicly Announced Program

   

Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program

 

5/1 - 5/31/13

    6,771     $ 29.54       6,771     $ 490,981  

6/1 - 6/30/13

    17,379     $ 29.19       17,379     $ 1,483,733  
                                 

Total

    24,150     $ 29.29       24,150          
 

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 June 26, 2013. 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, 2013

/s/ Michael C. Coffman

Date

Michael C. Coffman, President and

 

Chief Executive Officer

 

 

August 7, 2013

/s/ Lonnie J. Lowry

Date

Lonnie J. Lowry, Vice President

 

and Chief Financial Officer

 

 

August 7, 2013

/s/ Robb P. Winfield

Date

Robb P. Winfield, Controller

 

and Chief Accounting Officer

  

 

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