2012 Annual Report
For defined terms used in this report please see 

“Definitions” page of the attached Form 10-K.
To Our Fellow Shareholders

Fiscal 2012 was another challenging year, with natural 

gas prices being under downward pressure most of the 

year. In addition, the national and global economies 

added a different set of challenges to our overall 

business environment. In the face of these challenges 

our team at Panhandle was able to deliver both a strong 

financial year with solid earnings and a successful 

operational year. This performance continues to 

demonstrate that Panhandle’s disciplined, conservative 

and long-term focused business and operational 

strategies serve the Company well and continue to 

create value for its shareholders.

2012 Highlights

n Recorded net income of $7,370,996, $.88 per 

share for the year. 

n Increased 2012 total Mcfe production to 10.6 Bcfe,

a 19% increase and the largest in Company history.

n Increased 2012 oil production volumes 47% over 

2011 volumes.

n Generated cash from operating activities of $25.4 

million for the year, which fully funded drilling 

capital expenditures of $25.1 million. 

n Leased the Company’s mineral rights in certain 

western and northern Oklahoma plays for $6.5 

million in up front lease bonus payments and 

royalty in future production. The western Oklahoma 

lease was the most valuable leasing deal in

 Company history.

n Acquired approximately $20.1 million of producing 

properties and mineral acreage during 2012,

principally in the core of the Fayetteville Shale 

in Arkansas

Financial Review

The attached Form 10-K contains a complete discussion 

and analysis of the Company’s financial results for 2012 

on pages 24-35. A brief summary is provided in the two 

paragraphs below.

Panhandle recorded a 2012 net income of $7,370,996,

or $.88 per share, as compared to net income for 

2011 of $8,493,912, or $1.01 per share. Total revenues 

for 2012 increased to $48,532,317, as compared to 

$44,976,651 for 2011. The increase in revenues for 

2012 was the result of the Company recording lease 

bonus revenues of $7.2 million in 2012, as compared 

to $353,000 in 2011. Our average realized sales price 

for 2012 was $3.86 per Mcfe, as compared to $4.87 

per Mcfe for 2011. Although Mcfe production volumes 

increased 19% to 10,583,440 Mcfe in fiscal 2012, the 

average Mcfe sales price reduction of $1.01 materially 

reduced 2012 revenues and ultimately net income. 

Lease bonuses received overcame part of the revenue 

reduction from decreased product sales prices. 

Increased costs and expenses of $4.6 million,

principally DD&A costs, further contributed to the 

decline in net income. DD&A cost increases resulted 

from a 19% growth in production volumes in 2012,

higher finding costs per Mcfe in the oil and liquids-rich 

plays and negative price revisions reducing ultimate 

reserves, thus increasing the DD&A rate on a significant 

number of wells in the 2012 year-end reserve report. 

1

2012 Annual Report
Net cash provided by operating activities for 2012 was 

$25,371,196 as compared to $29,283,929 for 2011. 

The $7.3 million of cash proceeds from lease bonuses 

received this year is shown on the Company’s Statement 

of Cash Flows as a receipt in the Investing Activities 

section rather than being included in Cash Provided by 

Operating Activities. Capital expenditures for drilling and 

equipping wells and acquisitions of producing properties 

and mineral acreage totaled $45,291,427 for 2012 as 

compared to $27,545,348 for 2011. Capital expenditures 

for drilling and equipping wells increased $2.4 million 

this year with the remaining capital expenditure increase 

being in property acquisitions. 

Operational Highlights 

and Developments

In 2012, Panhandle accelerated the transition it began in 

2011 toward growth in oil and natural gas liquids (NGL) 

production and reserves. The Company’s 2012 oil 

production reached a record high of 153 Mbo, which was 

a 47% increase over 2011, and total Company oil and 

NGL production exceeded 250 Mbo in 2012. The 

Company’s 2012 proven oil reserves increased 27% 

over 2011 to 1,072 Mbo, while total proven oil and NGL 

reserves reached 1,861 Mbo. These increases in 

production and reserves are largely the result of the 

innovation and successful application of horizontal 

drilling and multi-stage hydraulic fracturing in oil well 

drilling, which is an extension of the same technology 

that led to the revival of natural gas drilling and 

production in the United States during the last decade. 

This innovation in oil drilling, coupled with the persistent 

value disparity between low natural gas prices compared 

to high oil prices, has led to a dramatic drop in natural 

gas well drilling and a material increase in oil well 

drilling throughout the United States. In recognition of 

this developing oil investment opportunity, Panhandle 

allocated approximately 53% of its approved drilling 

capital expenditures to oil and liquids-rich projects in 

2012. The majority of this investment was on the 

Company’s legacy mineral holdings in western 

Oklahoma and the Texas Panhandle; however, the 

Company also participated in a higher level of oil drilling 

on its mineral holdings in the Permian Basin of West 

Texas and New Mexico, as well as the developing 

southern Oklahoma Woodford Shale Oil Plays.

Through the transition toward growth in oil and NGL 

production and reserves, Panhandle has maintained 

its core strategy of maximizing long-term shareholder 

value through optimized development of the Company’s 

2








	




 



 



 



 
 
	

   



 

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extensive and diverse mineral holdings. The application 

of this strategy has resulted in another year of solid 

profitability for the Company during a period of 

extremely low natural gas prices. At the same time, as 

the Company’s oil and total production reached record 

highs, proved reserves grew 12% to 124.7 Bcfe, and 

3P (proved, probable and possible) reserves reached a 

record high of 442 Bcfe. In addition, the quality of the 

Company’s reserves has been substantially enhanced for 

year-end 2012 with the percentage of proved and 

probable reserves increasing significantly to 64% of 

total 3P reserves, versus 58% of total 3P reserves for 

year-end 2011.

Total Mcfe production also reached a new record high 

in 2012 of approximately 10.6 Bcfe, which was a 19% 

increase over 2011. In addition to a material rise in oil 

production, total Bcfe production benefited from the 

acquisition of properties and an active drilling program 

in the prolific core of the Fayetteville Shale where good 

rates of return are generated at existing natural gas 

futures prices. 

The ownership of legacy mineral holdings with minimal 

cost basis created tremendous flexibility for Panhandle 

in numerous ways during 2012. The Company continued 

to generate superior finding costs on wells in which it 

participated as a working interest owner, where 

Panhandle retains the royalty in wells drilled on its 

mineral acreage, in contrast to most oil and gas 

companies who lease a third party’s minerals and then 

must pay a royalty to that party. We negotiated royalty 

and lease bonuses on proposed wells that did not meet 

our investment criteria to warrant working interest 

participation. This occurred on approximately 24% of the 

proposals received in 2012. As production is established 

on these properties, the Company will receive a 

proportionate share of the non-cost bearing royalty 

production and associated revenue. In cases where plays 

were being aggressively leased by operators, and we 

calculated that the value of a certain level of cash lease 

bonus payment plus royalty interests in any wells drilled 

on the acreage would exceed the projected present 

worth of participating with a working interest in a play,

Panhandle leased blocks of minerals to the highest 

1 Prepared in accordance with Petroleum Resources Management System 3

2012 Annual Report









	




 

 


 

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  ­
Horizontal

Granite Wash & 

Hogshooter Wash

Horizontal 

Cleveland, 

Marmaton &

Tonkawa

average NRI of 3.3%. The Company generated a royalty 

interest in another 82 gross wells drilled in this area 

in 2012. 

The 47% increase in oil production experienced this year 

was largely the result of successful horizontal drilling in 

the Granite Wash, Marmaton, Cleveland and Tonkawa 

where the Company allocated approximately 35% of its 

approved drilling and completion capital expenditures. 

In addition to oil production, drilling in this area also 

contributes materially to the Company’s natural gas and 

NGL production. 

Panhandle owns 17,100 net mineral acres available for 

working interest participation in the 10-county area of 

western Oklahoma and the Texas Panhandle where the 

vast majority of this drilling is taking place. The key 

operators in this area continue to be very active, and 

management anticipates the development of 

Panhandle’s mineral holdings here will continue to be a 

significant part of our investment activity in 2013.

bidder. This situation occurred in two plays during 2012. 

The Company leased the majority of its mineral holdings 

in the northern Oklahoma Mississippian play and all of its 

holdings in the Roger Mills County, Oklahoma, Tonkawa 

play for a total of approximately $6,700,000 in lease 

bonus and retained a 3/16ths royalty interest in future 

production from wells drilled on these leases. In addition 

to generating the greatest expected cash flow, this 

strategy also eliminated future drilling investment risk 

for the Company in these plays. In aggregate, these two 

leases covered a portion of the rights in approximately 

5,300 net mineral acres or only 2.1% of the Company’s 

roughly 255,000 acres of total net mineral holdings.

Significant Plays

Western Oklahoma/Texas Panhandle

Western Oklahoma and the Texas Panhandle continued 

to be very active for the Company in 2012, where we 

participated in 81 gross working interest wells with an 

4

Western Oklahoma/Texas Panhandle
Anadarko 

Basin “Cana” 

Woodford

Shale

Anadarko Basin “Cana” Woodford Shale

Panhandle participated in 18 gross working interest 

wells with an average NRI of 2.2% in the Cana Woodford 

play during 2012. Seventeen of the wells were 

completed as producers for a 94% success rate. The 

Cana Woodford currently accounts for 7.2% of 

Panhandle’s total production.

Activity in the play prior to 2012 consisted primarily of 

operators drilling one well per unit in the core in order 

to hold leases, as well as drilling to define the economic 

boundaries of the field to the northwest. 2012 activity 

shifted significantly to infill development of the core. 

The core of the Cana Woodford yields prolific natural gas 

and NGLs and has become known as one of the nation’s 

premier natural gas liquids-rich plays. Panhandle holds 

1,394 core mineral acres with a total of 315 undeveloped 

drilling locations, assuming 8 total wells per unit. In 

2012, the play also expanded to the south into Grady,

Stephens, Garvin and McClain Counties, Oklahoma, 

where the Woodford Shale yields significantly higher oil 

and NGL production. Panhandle owns approximately 

1,950 net mineral acres available for working interest 

participation in this southern Cana Woodford and an 

additional 950 acres of leased minerals in the area, 

which will generate royalty production in wells drilled 

in those units. Key operators in this area continue to be 

very active in development drilling in the Cana core 

and in the southern oil and liquids expansion. 

Management anticipates that the development of our 

mineral holdings in this play will be a material part of 

our investment activity in 2013. 

Arkansas Fayetteville Shale

The Fayetteville Shale (Fayetteville) was the single most 

active investment area for the Company in 2012. The 

Company allocated approximately 44% of its approved 

2012 drilling and completion capital expenditures to this 

play and participated in 131 gross working interest wells 

with an average NRI of 3.6%. All of the wells were 

completed as producers for a 100% success rate. 

Panhandle had a royalty interest in another 133 gross 

wells drilled in this play in 2012. This year, the Company 

invested $20.1 million for the acquisition of working 

interest properties, minerals and overrides, principally 

5

2012 Annual Report

Western Oklahoma/Texas Panhandle
in the core of the Fayetteville. The acquired properties 

consisted of 196 PDP properties with approximately 9.5 

Bcfe of reserves, 164 undeveloped locations with 9.6 

Bcfe of PUD reserves and 435 undeveloped locations 

with 19.0 Bcfe of probable and possible reserves. 

Panhandle owns approximately 10,500 net mineral 

acres in the Fayetteville where, assuming 8 total wells 

per 640-acre unit, the Company has 800 undeveloped 

locations available for working interest participation 

with an average 4.8% NRI. In addition, there are another 

1,025 locations on leased minerals in the play, which 

will generate royalty production as wells are drilled. The 

Fayetteville currently accounts for 38.7% of Panhandle’s 

total production.

The Fayetteville has been established as one of the 

lowest cost dry gas resource plays in the United States, 

and, as the supply of gas comes into balance with 

demand, management believes that these strategic 

investments will yield substantial returns. The key 

operator in this area continues to be very active, and the 

development of Panhandle’s holdings here will continue 

to be a significant part of investment activity in 2013. 

Southeastern Oklahoma 

Woodford Shale

The southeastern Oklahoma Woodford Shale (SE OK 

Woodford) had modest activity in 2012 due to low 

natural gas prices during the year; however, the play still 

accounts for 19.3% of the Company’s current production. 

Panhandle owns 6,518 net mineral acres in the play 

where, assuming 8 total wells per 640-acre unit, there 

are 897 undeveloped locations available for working 

interest participation with an average of 4.4% NRI and 

an additional 359 locations on leased minerals in the 

play, which will generate royalty production as wells are 

drilled. As Panhandle owns perpetual mineral positions 

in the SE OK Woodford play, the undeveloped reserves 

6

Arkansas Fayetteville Shale
2012 Annual Report

will remain intact, and we are prepared to continue 

development of those reserves when natural gas market 

conditions are more favorable.

Looking Forward

In 2012, the Company negotiated and closed the 

largest leasing agreement, closed on the second largest 

acquisition in Panhandle’s history and grew production 

of oil and total Mcfe’s to record levels. In addition, the 

Company ended the year with a large number of wells 

approved, drilling or completing. All of the above put us 

in a very good position to continue our operational 

momentum in 2013. We plan to deploy drilling capital 

roughly equivalent to the 2012 level in 2013. Should 

there be an opportunity to invest in significantly more 

drilling or the right acquisition presents itself, we are well 

positioned financially to take full advantage of those 

opportunities. Management is always mindful that 

reinvesting cash flow in drilling projects or acquisitions 

that generate good rates of return will create value for 

the Company on a per share basis. Growth in production,

reserves and low finding costs will be the result of 

making those good investments.

The Company will continue for some time to be in a 

period of commodity price uncertainty and global 

economic turmoil. Panhandle is in a strong financial 

position, has an excellent asset base with the built-in 

capital efficiency of drilling on owned mineral acres and 

has proved, prudent and disciplined business strategies 

that will continue to deliver successful results for 

our shareholders.

Michael C. Coffman

President

Chief Executive Officer

Paul Blanchard

Senior Vice President 

Chief Operating Officer

7

SE Oklahoma Woodford Shale
Financial & Operating Highlights

Working Interest Wells

Category 2012 2011 2010

Drilling 9 10 11

Testing 51 32 21

Producing 116 114 62

 (27 oil, 89 gas) (20 oil, 94 gas) (4 oil, 58 gas)

Dry Holes 1 2 1

 Total 177 158 95

Royalty Interest Wells

Category 2012 2011 2010

Drilling, Testing 15 6 8

Producing 242 202 181

 (40 oil, 202 gas) (29 oil, 173 gas) (22 oil, 159 gas)

Dry Holes 2 0 0

Total 259 208 189

8

 2012 2011 2010

Revenue and Earnings 

Revenue $ 48,532,317 $ 44,976,651 $ 51,938,416

Net Income (loss) $ 7,370,996 $ 8,493,912 $ 11,419,690

Earnings (loss) per Share $ .88 $ 1.01 $ 1.36

Average Shares Outstanding 8,360,931 8,393,890 8,422,387

Net Cash Provided by Operating Activities $ 25,371,196 $ 29,283,929 $ 27,806,475

Costs Incurred In Oil and Gas Activities $ 46,193,825 $ 27,289,121 $ 11,958,024

Debt $ 14,874,985 $ 0 $ 0

 2012 (1) 2011 (1) 2010 (1)

Production

MCFE Produced 10,583,440 8,922,503 8,916,616

Increase (Decrease) from Prior Year 19% – (10%)

Average Sales Price per MCFE $ 3.86 $ 4.87 $ 4.94

Barrels Oil Produced 153,143 104,141 102,379

Average Sales Price per Barrel $ 90.13 $ 88.00 $ 72.83

MCF Natural Gas Produced 9,072,298 8,297,657 8,302,342

Average Sales Price per MCF $ 2.62 $ 4.13 $ 4.41

Barrels NGL Produced 98,714 – –

Average Sales Price per Barrel $ 33.23 – –

Average Production Costs (per mcf equivalent) (2) $ 1.00 $ 1.11 $ 1.08

(1) Proceeds from the sale of natural gas liquids have been included in natural gas sales and are reflected in the sales price per Mcf of natural gas for 

2010 and 2011. 2012 was the first year the Company produced sufficient volumes of NGL to warrant separate disclosure.

(2) Production costs include well operating costs, production taxes and handling, marketing and other fees paid on natural gas sales.

In 2012, Panhandle participated in 177 wells with a working interest and had a royalty interest in 259 wells that were either completed, drilling or 

testing at year end.
2012 Annual Report

Reserves & Production

9

 2012 2011 2010

Reserves

Proved Developed Reserves: 

Barrels of NGL (1) 494,160 386,774 –

Barrels of Oil 849,548 759,989 861,240

MCF of Gas 65,733,119 60,193,878 57,344,190

MCFE 73,795,367 67,074,456 62,511,630

Proved Undeveloped Reserves: 

Barrels of NGL (1) 294,582 404,874 –

Barrels of Oil 222,771 83,749 63,769

MCF of Gas 47,780,937 41,644,106 40,826,265

MCFE 50,885,055 44,575,844 41,208,879

Total Proved Reserves: 

Barrels of NGL (1) 788,742 791,648 –

Barrels of Oil 1,072,319 843,738 925,009

MCF of Gas 113,514,056 101,837,984 98,170,455

MCFE 124,680,422 111,650,300 103,720,509

Increase over prior year 12% 8% 74%

10% Discounted Estimated Future 

Net Cash Flows (before federal 

income taxes @ SEC pricing) 

Proved Developed $ 87,587,058 $ 106,464,138 $ 103,270,565

Proved Undeveloped $ 27,151,132 $ 29,977,891 $ 21,960,347

Total $ 114,738,190 $ 136,442,029 $ 125,230,912

SEC Pricing 

NGL/Barrel $ 35.70 $ 38.91 $ –

Oil/Barrel $ 89.41 $ 90.28 $ 69.23

Gas/MCF $ 2.51 $ 3.81 $ 4.33

(1) Year end 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve volumes disclosure. These NGL are associated with 

the continuing drilling activity in western Oklahoma and the Texas Panhandle, which includes many plays (horizontal Granite Wash, Hogshooter Wash, 

Cleveland, Marmaton, Tonkawa and the Anadarko Basin “Cana” Woodford Shale) producing significant volumes of NGL.
Comparison of 5-Year Cumulative 

Total Return*

Among Panhandle Oil & Gas Inc., The S&P Smallcap 600 Index 

and The S&P Oil & Gas Exploration & Production Index

10

The graph to the right compares the cumulative 5-year total 

return to shareholders on Panhandle Oil & Gas Inc’s common stock 

versus the cumulative total returns of the S&P Smallcap 600 

Index and the S&P Oil & Gas Exploration & Production Index. The 

graph assumes that the value of the investment in the Company’s 

common stock and in each of the indexes (including reinvestment 

of dividends) was $100 on 9/30/2007 and tracks it through 

9/30/2011. 

* $100 invested on 9/30/07 in stock or index-including 

reinvestment of dividends. Fiscal year ending September 30.

Copyright ©2012, S&P, a division of The McGraw-Hill Companies, Inc. 

All rights reserved.

Securities Information

The Company’s Class A Common Stock (“common stock”) is listed 

on the New York Stock Exchange (symbol PHX). The following 

table sets forth the high and low trade prices of the common stock 

during the periods indicated.

Quarter Ended High Low

December 31, 2010 $ 28.70 $ 23.75

March 31, 2011 $ 31.88 $ 25.60

June 30, 2011 $ 32.50 $ 27.30

September 30, 2011 $ 36.25 $ 26.36

December 31, 2011 $ 36.00 $ 26.18

March 31, 2012 $ 33.74 $ 28.05

June 30, 2012 $ 30.57 $ 24.16

September 30, 2012 $ 33.49 $ 27.85

As of November 22, 2012, there were 1,539 holders of record of 

Panhandle’s Class A common stock and approximately 3,900 

beneficial owners.

SEC and NYSE Certifications

The Form 10-K, included herein, which was filed by the Company 

with the Securities and Exchange Commission (SEC) for the fiscal 

year ended September 30, 2012, includes, as exhibits, the certifications of our chief executive officer and chief financial officer 

required to be filed with the SEC pursuant to Section 302 of the 

Sarbanes-Oxley Act of 2002. The Company has also filed with the 

New York Stock Exchange (NYSE) the 2012 annual certification 

of its chief executive officer confirming that the Company has 

complied with the NYSE corporate governance listing standards 

pursuant to Section 303A.12(a) of those standards.

During the past two years, cash dividends have been declared and 

paid as follows on the Class A Common Stock:

Date Rate Per Share

December 2010 $ 0.07

March 2011 $ 0.07

June 2011 $ 0.07

September 2011 $ 0.07

December 2011 $ 0.07

March 2012 $ 0.07

June 2012 $ 0.07

September 2012 $ 0.07

While the Company expects to continue to pay dividends on its 

common stock, the payment of future cash dividends will depend 

upon, among other things, financial condition, funds from 

operations, the level of capital and development expenditures, 

future business prospects, contractual restrictions and any other 

factors considered relevant by the board of directors. The 

Company’s credit facility also contains provisions limiting the 

amount of dividends that can be paid.

Stock Split History

May 1982 10-for-1

May 1999 3-for-1

February 2004 2-for-1

January 2006 2-for-1
2012 Annual Report

Corporate Headquarters

Grand Centre Building

5400 N. Grand Blvd.

Suite 300

Oklahoma City, OK 73112

Internet Address

Company financial information, public 

disclosures and other information are 

available through Panhandle’s website at: 

www.panhandleoilandgas.com

Officers

Paul Blanchard

Senior Vice President 

Chief Operating Officer

Ben Spriestersbach

Vice President, Land

Lonnie J. Lowry

Vice President 

Chief Financial Officer, Secretary

Robb Winfield

Controller 

Chief Accounting Officer

Michael C. Coffman

President

Chief Executive Officer

11

Stock Transfer & Dividend Paying Agent

Standard U.S. postal mail:

Computershare Trust Company, N.A.

P.O. Box 43078

Providence, RI 02940-3078

Overnight/express delivery:

Computershare Trust Company, N.A.

250 Royall Street

Canton, MA 02021

Toll free within U.S. and Canada 

 1-800-884-4225

Outside U.S. and Canada 

 1-781-575-4706

Website: 

 www.computershare.com

Email inquiry address for investors:

 web.queries@computershare.com

Counsel

Lon Foster III

Fellers, Snider, Blankenship, Bailey 

& Tippens, P.C.

Tulsa, Oklahoma

Stock Exchange

New York Stock Exchange

Symbol: PHX

Independent Registered Public 

Accounting Firm

Ernst & Young LLP

Oklahoma City, Oklahoma
(1) Member audit committee

(2) Member compensation committee

(3) Member governance and nominating committee

Board Of Directors

Bruce M. Bell

Edrio Oil Company

(Retired from the Board December 2012)

(2) (3)

Michael C. Coffman

President

Chief Executive Officer

Duke R. Ligon

Attorney

(1) (3)

Robert E. Robotti

Robotti & Company, LLC

(2) (3)

Robert A. Reece

Attorney

(1) (3)

Robert O. Lorenz

Lead Independent Director

(1) (2)

 H. Grant Swartzwelder

PetroGrowth Advisors

(2) (3)

Darryl G. Smette

Executive Vice President of Marketing 

& Midstream

Devon Energy Corporation

(1) (2)

12
UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

 OKLAHOMA 73-1055775 

(State or other jurisdiction of incorporation (I.R.S. Employer Identification No.)

 or organization)

Grand Centre, Suite 300, 5400 N. Grand Blvd., Oklahoma City, OK 73112 

(Address of principal executive offices) (Zip code)

Registrant’s telephone number: (405) 948-1560

Securities registered under Section 12(b) of the Act: 

CLASS A COMMON STOCK (VOTING) NEW YORK STOCK EXCHANGE

(Title of Class) (Name of each exchange on which registered)

Securities registered under Section 12(g) of the Act:

 (Title of Class)

 

CLASS B COMMON STOCK (NON-VOTING) $1.00 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities 

Act. Yes X No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the 

Act. Yes X No

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

(Facing Sheet Continued)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2012

Commission File Number: 001-31759

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this 

chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive 

proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this 

Form 10-K. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated 

filer. See definition of “accelerated filer and large accelerated filer” 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 Act).

 Yes X No

The aggregate market value of the voting stock held by non-affiliates of the registrant, computed by using the 

closing price of registrant’s Common Stock, at March 31, 2012, was $206,798,928. As of December 1, 2012, 

8,250,192 shares of Class A Common Stock were outstanding.

Documents Incorporated By Reference

The information required by Part III of this Report, to the extent not set forth herein, is incorporated by reference 

from the registrant’s Definitive Proxy Statement relating to the annual meeting of stockholders to be held on 

March 7, 2013, which definitive proxy statement will be filed with the Securities and Exchange Commission 

within 120 days after the end of the fiscal year to which this Report relates.
T A B L E O F C O N T E N T S

PART I Page

Item 1 Business.......................................................................................................................1 

Item 1B Unresolved Staff Comments .....................................................................................11

Item 2 Properties...................................................................................................................12

Item 3 Legal Proceedings.....................................................................................................21

Item 4 Submission of Matters to a Vote of

 Security Holders...................................................................................................21

PART II

Item 5 Market for Common Equity, Related Stockholder Matters

 and Unregistered Sales of Equity Securities........................................................22

Item 6 Selected Financial Data.............................................................................................24

Item 7 Management’s Discussion and Analysis of Financial

 Condition and Results of Operations ...................................................................24

Item 7A Quantitative and Qualitative Disclosures about Market 

 Risk.......................................................................................................................40

Item 8 Financial Statements and Supplementary Data.........................................................41

Item 9 Changes in and Disagreements with Accountants on Accounting 

 and Financial Disclosure ......................................................................................79

Item 9A Controls and Procedures............................................................................................79

Item 9B Other Information......................................................................................................79

PART III

Item 10-14 Incorporated by Reference to Proxy Statement.........................................................80 

PART IV

Item 15 Exhibits, Financial Statement Schedules and Reports on Form 8- K .......................80
DEFINITIONS

The following defined terms are used in this report: 

“Bbl” means barrel; 

“Bcf” means billion cubic feet; 

“Board” means board of directors;

“BTU” means British Thermal Units; 

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

“CEO” means Chief Executive Officer;

“CFO” means Chief Financial Officer;

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

“COO” means Chief Operating Officer;

“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;

“gross wells” or “gross acres” are the wells or acres in which the Company has a working or royalty 

interest; 

“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; 

“Mcfd” means thousand cubic feet per day; 

“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; 

“Mmcf” means million cubic feet;

“Mmcfe” means natural gas stated on an Mmcf basis and crude oil and natural gas liquids converted to a 

million cubic feet of natural gas equivalent by using the ratio of one thousand Bbl of crude oil or 

natural gas liquids to six Mmcf 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;

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

“PDP” means proved developed producing;

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

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

“PUD” means proved undeveloped;

“PV-10” means estimated pre-tax present value of future net revenues discounted at 10% using SEC 

rules;

“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.

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

References to 2010 natural gas reserves, production, sales and prices include associated NGL.

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

properties.
(1)

PART I

ITEM 1 BUSINESS

GENERAL

Panhandle Oil and Gas Inc. was founded in Range, Texas County, Oklahoma, in 1926, as 

Panhandle Cooperative Royalty Company and operated as a cooperative until 1979, when the Company 

merged into Panhandle Royalty Company and its shares became publicly traded. On April 2, 2007, the 

Company’s name was changed to Panhandle Oil and Gas Inc. The name change was made to clear up 

confusion as to whether the Company was a royalty trust. Panhandle has never been a royalty trust.

While operating as a cooperative, the Company distributed most of its net income to shareholders 

as cash dividends. Upon conversion to a public company in 1979, although still paying dividends, the 

Company began to retain a substantial part of its cash flow to participate with a working interest in the 

drilling of wells on its mineral acreage and to purchase additional mineral acreage. Several acquisitions 

of additional mineral acreage and small companies were made in the ‘80s and ‘90s, and the acquisition of 

Wood Oil Company, as a wholly owned subsidiary, was consummated in October 2001. Wood Oil 

Company was merged into Panhandle Oil and Gas Inc. effective July 1, 2011.

In January 2006, the Company last split its Class A Common Stock on a two-for-one basis. In 

March 2007 the Company last increased its authorized Class A Common Stock from 12 million shares to 

24 million shares.

The Company is involved in the acquisition, management and development of non-operated oil 

and natural gas properties, including wells located on the Company’s mineral and leasehold acreage. 

Panhandle’s mineral and leasehold properties are located primarily in Arkansas, New Mexico, North 

Dakota, Oklahoma and Texas, with properties also located in several other states. The majority of the 

Company’s oil, NGL and natural gas production is from wells located in Oklahoma. 

The Company’s office is located at Grand Centre, Suite 300, 5400 N. Grand Blvd., Oklahoma 

City, OK 73112; telephone – (405) 948-1560; facsimile – (405) 948-2038. The Company’s website is 

www.panhandleoilandgas.com.

The Company files periodic reports with the SEC on Forms 10-Q and 10-K. These Forms, the 

Company’s annual report to shareholders and current press releases are available free of charge through 

our website as soon as reasonably practicable after they are filed with the SEC. Also, the Company posts 

copies of its various corporate governance documents on the website. From time to time, the Company 

posts other important disclosures to investors in the “Press Release” or “Upcoming Events” section of the 

website, as allowed by SEC rules.

Materials filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 

F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may 

be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet website at 

www.sec.gov that contains reports, proxy and information statements, and other information regarding 

the Company that has been filed electronically with the SEC, including this Form 10-K.

BUSINESS STRATEGY

Typically, most of Panhandle’s revenues are derived from the production and sale of oil, NGL 

and natural gas (see Item 8 - “Financial Statements and Supplementary Data”). The Company’s oil and 

natural gas properties, including its mineral acreage, leasehold acreage and working and royalty interests
(2)

in producing wells are mainly in Oklahoma with other significant holdings in Arkansas, New Mexico, 

North Dakota and Texas (see Item 2 – “Properties”). Exploration and development of the Company’s oil 

and natural gas properties are conducted in association with oil and natural gas exploration and 

production companies, primarily larger independent companies. The Company does not operate any of its 

oil and natural gas properties, but has been an active working interest participant for many years in wells 

drilled on the Company’s mineral properties and on third-party drilling prospects. A significant 

percentage of the Company’s recent drilling participations has been on properties in which the Company 

owns mineral acreage and, in many cases, already owns an interest in a producing well in the drilling and 

spacing unit. Most of these wells are in unconventional plays (shale gas) located in Oklahoma and 

Arkansas.

PRINCIPAL PRODUCTS AND MARKETS

The Company’s principal products are natural gas and, to a lesser extent, crude oil and NGL. 

These products are sold to various purchasers, including pipeline and marketing companies, which 

service the areas where the Company’s producing wells are located. Since the Company does not operate 

any of the wells in which it owns an interest, it relies on the operating expertise of numerous companies 

that operate wells in the areas where the Company owns interests. This includes expertise in the drilling 

and completion of new wells, producing well operations and, in most cases, the marketing or purchasing 

of production from the wells. Natural gas and NGL sales are principally handled by the well operator and 

are normally contracted on a monthly basis with third-party natural gas marketers and pipeline 

companies. Payment for natural gas and NGL sold is received by the Company from the well operator or 

the contracted purchaser. Crude oil sales are generally handled by the well operator and payment for oil 

sold is received by the Company from the well operator or from the crude oil purchaser.

Prices of oil, NGL and natural gas are dependent on numerous factors beyond the control of the 

Company, including competition, weather, international events and circumstances, supply and demand, 

actions taken by the Organization of Petroleum Exporting Countries (“OPEC”), and economic, political 

and regulatory developments. Since demand for natural gas is generally highest during winter months, 

prices received for the Company’s natural gas production are subject to seasonal variations. 

The Company enters into price risk management financial instruments (derivatives) to reduce the 

Company’s exposure to short-term fluctuations in the price of oil and natural gas. The derivative 

contracts apply to only a portion of the Company’s oil and natural gas production and provide only 

partial price protection against declines in oil and natural gas prices. These derivative contracts expose 

the Company to risk of financial loss and may limit the benefit of future increases in oil and natural gas 

prices. A more thorough discussion of these derivative contracts, including risk of financial loss, is 

contained in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of 

Operations.”

COMPETITIVE BUSINESS CONDITIONS

The oil and natural gas industry is highly competitive, particularly in the search for new oil, NGL

and natural gas reserves. Many factors affect Panhandle’s competitive position and the market for its 

products which are beyond its control. Some of these factors include the quantity and price of foreign oil 

imports; domestic supply of oil, NGL and natural gas; changes in prices received for oil, NGL and 

natural gas production; business and consumer demand for refined oil products, NGL and natural gas; 

and the effects of federal and state regulation of the exploration for, production of and sales of oil, NGL 

and natural gas. Changes in existing economic conditions, political developments, weather patterns and 

actions taken by OPEC and other oil-producing countries have a dramatic influence on the price 

Panhandle receives for its oil, NGL and natural gas production.
(3)

The Company does not operate any of the wells in which it has an interest; rather it relies on 

companies with greater resources, staff, equipment, research and experience for operation of wells both 

in the drilling and production phases. The Company’s business strategy is to use its strong financial base 

and its mineral and leasehold acreage ownership, coupled with its own geologic and economic 

evaluations, to elect to participate in drilling operations with these larger companies or to lease or 

farmout its mineral or leasehold acreage while retaining a royalty interest. This strategy allows the 

Company to compete effectively in drilling operations it could not undertake on its own due to financial 

and personnel limits while maintaining low overhead costs.

SOURCES AND AVAILABILITY OF RAW MATERIALS

The existence of recoverable oil, NGL and natural gas reserves in commercial quantities is 

essential to the ultimate realization of value from the Company’s mineral and leasehold acreage. These 

mineral and leasehold properties are essentially the raw materials to our business. The production and 

sale of oil, NGL and natural gas from the Company’s properties are essential to provide the cash flow 

necessary to sustain the ongoing viability of the Company. The Company reinvests a portion of its cash 

flow to purchase oil and natural gas mineral and leasehold acreage to assure the continued availability of 

acreage with which to participate in exploration, drilling and development operations and, subsequently, 

the production and sale of oil, NGL and natural gas. This participation in exploration and production 

activities and purchase of additional acreage is necessary to continue to supply the Company with the raw 

materials with which to generate additional cash flow. Mineral and leasehold acreage purchases are made 

from many owners. The Company does not rely on any particular companies or persons for the purchases 

of additional mineral and leasehold acreage.

MAJOR CUSTOMERS

The Company’s oil, NGL and natural gas production is sold, in most cases, through its well 

operators to many different purchasers on a well-by-well basis. During 2012, sales through three separate 

well operators accounted for approximately 15%, 13% and 10% of the Company’s total oil, NGL and 

natural gas sales. During 2011, sales through two separate well operators accounted for approximately 

15% and 14% of the Company’s total oil, NGL and natural gas sales. During 2010, sales through three 

separate well operators accounted for approximately 15%, 14% and 11% of the Company’s total oil, 

NGL and natural gas sales. Generally, if one purchaser declines to continue purchasing the Company’s 

production, several other purchasers can be located. Pricing is generally consistent from purchaser to 

purchaser.

PATENTS, TRADEMARKS, LICENSES, FRANCHISES AND ROYALTY AGREEMENTS

The Company does not own any patents, trademarks, licenses or franchises. Royalty agreements 

on wells producing oil, NGL and natural gas stemming from the Company’s ownership of mineral 

acreage generate a portion of the Company’s revenues. These royalties are tied to ownership of mineral 

acreage, and this ownership is perpetual, unless sold by the Company. Royalties are due and payable to 

the Company whenever oil, NGL and natural gas is produced and sold from wells located on the 

Company’s mineral acreage.

REGULATION

All of the Company’s well interests and non-producing properties are located onshore in the 

United States. Oil, NGL and natural gas production is subject to various taxes, such as gross production 

taxes and, in some cases, ad valorem taxes.
(4)

The State of Oklahoma and other states require permits for drilling operations, drilling bonds and 

reports concerning operations and impose other regulations relating to the exploration for and production 

of oil, NGL and natural gas. These states also have regulations addressing conservation matters, 

including provisions for the unitization or pooling of oil and natural gas properties and the regulation of 

spacing, plugging and abandonment of wells. These regulations vary from state to state. As previously 

discussed, the Company relies on its well operators to comply with governmental regulations.

Various aspects of the Company’s oil and natural gas operations are regulated by agencies of the 

federal government. Transportation of natural gas in interstate commerce is generally regulated by the 

Federal Energy Regulatory Commission (“FERC”) pursuant to the Natural Gas Act of 1938 and the 

Natural Gas Policy Act of 1978 (“NGPA”). The intrastate transportation and gathering of natural gas 

(and operational and safety matters related thereto) may be subject to regulation by state and local 

governments. 

FERC’s jurisdiction over interstate natural gas sales was substantially modified by the NGPA 

under which FERC continued to regulate the maximum selling prices of certain categories of natural gas 

sold in “first sales” in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural 

Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of 

natural gas. Because “first sales” include typical wellhead sales by producers, all natural gas produced 

from the Company’s natural gas properties is sold at market prices, subject to the terms of any private 

contracts in effect. FERC’s jurisdiction over natural gas transportation was not affected by the Decontrol 

Act.

Sales of natural gas are affected by intrastate and interstate natural gas transportation regulation. 

Beginning in 1985, FERC adopted regulatory changes that have significantly altered the transportation 

and marketing of natural gas. These changes were intended by FERC to foster competition by 

transforming the role of interstate pipeline companies from wholesale marketers of natural gas to the 

primary role of natural gas transporters. As a result of the various omnibus rulemaking proceedings in the 

late 1980s and the individual pipeline restructuring proceedings of the early to mid-1990s, interstate 

pipelines must provide open and nondiscriminatory transportation and transportation-related services to 

all producers, natural gas marketing companies, local distribution companies, industrial end users and 

other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar 

interstate services, FERC expanded the impact of open access regulations to intrastate commerce.

More recently, FERC has pursued other policy initiatives that have affected natural gas 

marketing. Most notable are: (1) permitting the large-scale divestiture of interstate pipeline-owned 

natural gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules 

governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards 

relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make 

transportation information available on a timely basis and to enable transactions to occur on a purely 

electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and 

its relationship to open access service in the primary market; and (5) development of policy and 

promulgation of orders pertaining to its authorization of market-based rates (rather than traditional costof-service based rates) for transportation or transportation-related services upon the pipeline’s 

demonstration of lack of market control in the relevant service market. 

As a result of these changes, sellers and buyers of natural gas have gained direct access to the 

particular pipeline services they need and are able to conduct business with a larger number of counter 

parties. These changes generally have improved the access to markets for natural gas while substantially 

increasing competition in the natural gas marketplace. The effect of future regulations by FERC and 

other regulatory agencies cannot be predicted. 
(5)

Sales of oil are not regulated and are made at market prices. The price received from the sale of 

oil is affected by the cost of transporting it to market. Much of that transportation is through interstate 

common carrier pipelines. Effective January 1, 1995, FERC implemented regulations generally 

grandfathering all previously approved interstate transportation rates and establishing an indexing system 

for those rates by which adjustments are made annually based on the rate of inflation, subject to certain 

conditions and limitations. Over time, these regulations tend to increase the cost of transporting oil by 

interstate pipelines, although some annual adjustments may result in decreased rates for a given year. 

These regulations have generally been upheld on judicial review. Every five years, FERC will examine 

the relationship between the annual change in the applicable index and the actual cost changes 

experienced by the oil pipeline industry. 

ENVIRONMENTAL MATTERS

As the Company is directly involved in the extraction and use of natural resources, it is subject to 

various federal, state and local laws and regulations regarding environmental and ecological matters. 

Compliance with these laws and regulations may necessitate significant capital outlays; however, to date, 

the Company’s cost of compliance has been immaterial. The Company does not believe the existence of 

these environmental laws, as currently written and interpreted, will materially hinder or adversely affect 

the Company’s business operations; however, there can be no assurances of future events or changes in 

laws, or the interpretation of laws, governing our industry. Current discussions involving the governance 

of hydraulic fracturing in the future could have a material impact on the Company. Since the Company 

does not operate any wells in which it owns an interest, actual compliance with environmental laws is 

controlled by the well operators, with Panhandle being responsible for its proportionate share of the costs 

involved. As such, to its knowledge, the Company is not aware of any instances of non-compliance with 

existing laws and regulations and that, absent an extraordinary event, any noncompliance will not have a 

material adverse effect on the financial condition of the Company. Although the Company is not fully 

insured against all environmental risks, insurance coverage is maintained at levels which are customary 

in the industry.

EMPLOYEES

At September 30, 2012, Panhandle employed 20 persons on a full-time basis with five of the 

employees serving as executive officers. The President and CEO is also a director of the Company.

RISK FACTORS

In addition to the other information included in this Form 10-K, the following risk factors should 

be considered in evaluating the Company’s business and future prospects. If any of the following risk 

factors should occur, the Company’s financial condition could be materially impacted and the holders of 

our securities could lose part or all of their investment in Panhandle. The risk factors described below are 

not necessarily exhaustive, and investors are encouraged to perform their own investigation with respect 

to the Company and its business. Investors should also read the other information in this Form 10-K, 

including the financial statements and related notes.

Economic conditions, worldwide and in the United States, may have a significant negative effect on 

operating results, liquidity and financial condition.

Effects of domestic and international economic conditions, could lead to: (1) a decline in demand 

for oil, NGL and natural gas resulting in decreased oil, NGL and natural gas reserves due to curtailed 

drilling activity; (2) a decline in oil, NGL and natural gas prices; (3) risk of insolvency of well operators 

and oil, NGL and natural gas purchasers; (4) limited availability of certain insurance coverage; and (5) 

limited access to derivative instruments. A decline in reserves would lead to a decline in production, and
(6)

either a production decline, or a decrease in oil, NGL and natural gas prices, would have a negative 

impact on the Company’s cash flow, profitability and value.

Oil, NGL and natural gas prices are volatile. Volatility in these prices can adversely affect 

operating results and the price of the Company’s Common Stock. This volatility also makes 

valuation of oil and natural gas producing properties difficult and can disrupt markets.

Oil, NGL and natural gas prices have historically been, and will likely continue to be, volatile. 

The prices for oil, NGL and natural gas are subject to wide fluctuation in response to a number of factors, 

including:

• worldwide economic conditions;

• economic, political and regulatory developments;

• market uncertainty;

• relatively minor changes in the supply of and demand for oil, NGL and natural gas; 

• availability and capacity of necessary transportation and processing facilities;

• commodity futures trading;

• weather conditions;

• political instability or armed conflicts in major oil and natural gas producing regions, 

 particularly the Middle East and West Africa;

• actions taken by OPEC;

• competition from alternative sources of energy; and

• technological advancements affecting energy consumption and energy supply.

In recent years, oil, NGL and natural gas price volatility has been severe. Price volatility makes it 

difficult to budget and project the return on investment in exploration and development projects and to 

estimate with precision the value of producing properties that are owned or acquired by the Company. In 

addition, volatile prices often disrupt the market for oil and natural gas properties, as buyers and sellers 

have more difficulty agreeing on the purchase price of properties. Revenues, results of operations and 

profitability may fluctuate significantly as a result of variations in oil, NGL and natural gas prices and 

production performance.

Lower oil, NGL and natural gas prices may also trigger significant impairment write-downs on a 

portion of the Company’s properties.

A substantial decline in oil, NGL and natural gas prices for an extended period of time would have 

a material adverse effect on the Company.

A substantial decline in oil, NGL and natural gas prices for an extended period of time would 

have a material adverse effect on the Company’s financial position, results of operations, access to capital 

and the quantities of oil, NGL and natural gas that may be economically produced. A significant decrease 

in price levels for an extended period would have a material negative effect in several ways, including:

• cash flow would be reduced, decreasing funds available for capital expenditures employed to 

 replace reserves or increase production;

• future undiscounted and discounted net cash flows from producing properties would decrease, 

possibly resulting in impairment expense that may be significant;

• certain reserves may no longer be economic to produce, leading to both lower proved reserves 

and cash flow; and

• access to sources of capital, such as equity or long-term debt markets, could be severely 

 limited or unavailable.
(7)

We cannot control activities on properties we do not operate. 

The Company does not operate any of the properties in which it has an interest and has very 

limited ability to exercise influence over operations of these properties or their associated costs. Our 

dependence on the operator and other working interest owners for these projects and the limited ability to 

influence operations and associated costs could materially and adversely affect the realization of targeted 

returns on capital in drilling or acquisition activities and targeted production growth rates. The success 

and timing of drilling, development and exploitation activities on properties operated by others depend on 

a number of factors that are beyond the Company’s control, including the operator’s expertise and 

financial resources, approval of other participants for drilling wells and utilization of appropriate 

technology.

The Company’s derivative activities may reduce the cash flow received for oil and natural gas 

sales.

In order to manage exposure to price volatility on our oil and natural gas production, we enter into 

oil and natural gas derivative contracts for a portion of our expected production. Oil and natural gas price 

derivatives may limit the cash flow we actually realize and therefore reduce the Company’s ability to 

fund future projects. Also, the fair value of our oil and natural gas derivative contracts may vary 

significantly from period to period, therefore materially affecting reported earnings.

There is risk associated with our derivative contracts that involves the possibility that 

counterparties may be unable to satisfy contractual obligations to us. If any counterparty to our derivative 

instruments were to default or seek bankruptcy protection, it could subject a larger percentage of our 

future oil and natural gas production to commodity price changes and could have a negative effect on our 

ability to fund future projects.

The fair value of our oil and natural gas derivative instruments outstanding as of September 30, 

2012, was a liability of $172,271.

A more thorough discussion of these derivative contracts, including risk of financial loss, is 

contained in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of 

Operations.”

Lower oil, NGL and natural gas prices or negative adjustments to oil, NGL and natural gas 

reserves may result in significant impairment charges.

The Company has elected to utilize the successful efforts method of accounting for its oil and 

natural gas exploration and development activities. Exploration expenses, including geological and 

geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of 

successful wells and related production equipment and development dry holes are capitalized and 

amortized by property using the unit-of-production method (the ratio of oil, NGL and natural gas 

volumes produced to total proved or proved developed reserves is used to amortize the remaining asset 

basis on each producing property) as oil, NGL and natural gas are produced. 

All long-lived assets, principally the Company’s oil and natural gas properties, are monitored for 

potential impairment when circumstances indicate that the carrying value of the asset on our books may 

be greater than its future net cash flows. The need to test a property for impairment may result from 

declines in oil, NGL and natural gas sales prices or unfavorable adjustments to oil, NGL and natural gas 

reserves. Once assets are classified as held for sale, they are reviewed for impairment. Because of the 

uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges 

will be recorded. If an impairment charge is recognized, cash flow from operating activities is not
(8)

impacted, but net income and, consequently, shareholders’ equity are reduced.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. 

Any material inaccuracies in these reserve estimates or underlying assumptions will materially 

affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of oil, NGL and natural gas in an exact 

way. Oil, NGL and natural gas reserve engineering requires subjective estimates of underground 

accumulations of oil, NGL and natural gas and assumptions concerning future prices of these 

commodities, future production levels, and operating and development costs. In estimating our reserves, 

we and our Independent Consulting Petroleum Engineering Firm make certain assumptions that may 

prove to be incorrect, including assumptions relating to the level of oil, NGL and natural gas prices, 

future production levels, capital expenditures, operating and development costs, the effects of regulation 

and availability of funds. If these assumptions prove to be incorrect, our estimates of reserves (the 

economically recoverable quantities of oil, NGL and natural gas attributable to any particular group of 

properties), the classifications of reserves based on risk of recovery and our estimates of the future net 

cash flows from our reserves could change significantly. 

Our standardized measure of oil and natural gas reserves is calculated using the 12-month average 

price calculated as the unweighted arithmetic average of the first-day-of-the-month individual product 

prices for each month within the 12-month period prior to September 30 held flat over the life of the 

properties and costs in effect as of the date of estimation, less future development, production and income 

tax expenses, and is discounted at 10% per annum to reflect the timing of future net revenue in 

accordance with the rules and regulations of the SEC. Over time, we may make material changes to 

reserve estimates to take into account changes in our assumptions and the results of actual development 

and production. 

The reserve estimates made for fields that do not have a lengthy production history are less 

reliable than estimates for fields with lengthy production histories. A lack of production history may 

contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of 

development expenditures. Further, our lack of knowledge of all individual well information known to 

the well operators such as incomplete well stimulation efforts, restricted production rates for various 

reasons and up to date well production data, etc. may cause differences in our reserve estimates. 

Because forward-looking prices and costs are not used to estimate discounted future net cash 

flows from our estimated proved reserves, the standardized measure of our estimated proved reserves is 

not necessarily the same as the current market value of our estimated proved oil, NGL and natural gas 

reserves.

The timing of both our production and our incurrence of expenses in connection with the 

development and production of our properties will affect the timing of actual future net cash flows from 

proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when 

calculating discounted future net cash flows in compliance with the FASB statement on oil and natural 

gas producing activities disclosures may not be the most appropriate discount factor based on interest 

rates in effect from time to time and risks associated with the Company, or the oil and natural gas 

industry in general.

Failure to find or acquire additional reserves will cause reserves and production to decline 

materially from their current levels.

The rate of production from oil and natural gas properties generally declines as reserves are 

depleted. The Company’s proved reserves will decline materially as reserves are produced except to the
(9)

extent that the Company acquires additional properties containing proved reserves, conducts additional 

successful exploration and development drilling, successfully applies new technologies or identifies 

additional behind-pipe zones (different productive zones within existing producing well bores) or 

secondary recovery reserves. The above activities are conducted with well operators, as the Company 

does not operate any of its wells. Future oil, NGL and natural gas production is therefore highly 

dependent upon the level of success in acquiring or finding additional reserves.

Drilling for oil and natural gas invariably involves unprofitable efforts, not only from dry wells 

but also from wells that are productive but do not produce sufficient reserves to return a profit after 

deducting drilling, operating and other costs. In addition, wells that are profitable may not achieve a 

targeted rate of return. The Company relies on the operators’ seismic data and other advanced 

technologies in identifying prospects and in conducting exploration and development activities. The 

seismic data and other technologies used do not allow operators to know conclusively prior to drilling a 

well whether oil, NGL or natural gas is present and may be commercially produced.

Cost factors can adversely affect the economics of any project, and ultimately the cost of drilling, 

completing and operating a well is controlled by well operators and existing market conditions. Further, 

drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including 

unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures 

or accidents, adverse weather conditions, environmental and other governmental requirements, the cost 

and availability of drilling rigs, equipment and services and the expected sales price to be received for oil, 

NGL or natural gas produced from the wells.

Oil and natural gas drilling and producing operations involve various risks.

The Company is subject to all the risks normally incident to the operation and development of oil 

and natural gas properties including well blowouts, cratering and explosions, pipe failures, adverse 

weather conditions, fires, abnormal pressures, uncontrollable flows of oil and natural gas, brine or well 

fluids, release of contaminants into the environment and other environmental hazards and risks.

Other risks of operations include oilfield services shortages, equipment shortages, shortages of 

qualified oilfield workers, pipeline and gathering system capacity constraints, transportation interruptions 

and lack of processing access to gas plants.

The Company maintains insurance against many potential losses or liabilities arising from well 

operations in accordance with customary industry practices and in amounts believed by management to 

be prudent. However, this insurance does not protect it against all operational and environmental risks. 

For example, the Company does not maintain business interruption insurance. Additionally, pollution and 

environmental risks generally are not fully insurable. These risks could give rise to significant uninsured 

costs that could have a material adverse effect on the Company’s financial results.

Debt level and interest rates may adversely affect our business.

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving 

loan with a limit in the amount of $80,000,000. As of September 30, 2012, the Company had a balance of 

$14,874,985 drawn on the facility. The facility has a current borrowing base of $35,000,000, is secured 

by certain of the Company’s properties and contains certain restrictive covenants.

Should the Company incur substantial indebtedness under its credit facility to fund capital 

projects or for other reasons, there is risk of it adversely affecting our business operations as follows:
(10)

• cash flows from operating activities required to service indebtedness will not be available for 

 other purposes;

• covenants contained in the Company’s borrowing agreement may limit our ability to borrow 

 additional funds and pay dividends;

• any limitation on the borrowing of additional funds may affect our ability to fund capital 

projects and may also affect how we will be able to react to economic and industry changes; 

 and

• a significant increase in the interest rate on our credit facility will limit funds available for 

 other purposes.

The borrowing base of our corporate revolving bank credit facility is subject to periodic 

redetermination and is based in part on oil, NGL and natural gas prices. A lowering of our borrowing 

base because of lower oil, NGL or natural gas prices, or for other reasons, could require us to repay 

indebtedness in excess of the borrowing base, or we might need to further secure the debt with additional 

collateral. Our ability to meet any debt obligations depends on our future performance. General economic 

conditions, prices and financial, business and other factors affect our future performance, and many of 

these factors are beyond our control. In addition, our failure to comply with the restrictive covenants 

relating to our credit facility could result in a default, which could adversely affect our business, financial 

condition and results of operations.

Future legislative or regulatory changes may result in increased costs and decreased revenues, cash 

flows and liquidity.

Companies that operate wells in which Panhandle owns a working interest are subject to 

extensive federal, state and local regulation. Panhandle, as a working interest owner, is therefore 

indirectly subject to these same regulations. New or changed laws and regulations such as those 

described below could have an adverse effect on our business.

Federal Income Taxation

 Proposals to repeal the expensing of intangible drilling costs, repeal the percentage 

depletion allowance and increase the amortization period of geological and geophysical expenses, 

if enacted, would increase and accelerate the Company’s payment of federal income taxes. As a 

result, these changes would decrease the Company’s cash flows available for developing its oil 

 and natural gas properties.

 Hydraulic Fracturing

The vast majority of oil and natural gas wells drilled in recent years have been, and future 

wells expected to be drilled are expected to be, hydraulically fractured as a part of the process of 

completing the wells and putting them on production. Some members of Congress have proposed 

 legislation to either ban or further regulate the hydraulic fracturing process. We cannot predict 

whether any such legislation will be enacted or, if enacted, what its provisions would be. If 

legislation is passed to ban hydraulic fracturing, the number of wells drilled in the future will 

most likely drop dramatically, and the economic performance of those drilled will be negatively 

 affected. Legislation imposing further regulation of hydraulic fracturing may result in increased 

costs to drill, complete and operate wells, as well as delays in obtaining permits to drill wells.
(11)

Climate Change

 The EPA has proposed regulations for the purpose of restricting greenhouse gas emissions 

from stationary sources. Such regulatory and legislative proposals to restrict greenhouse gas 

emissions, or to generally address climate change, could increase the Company’s operating costs 

as operators of wells, in which the Company owns a working interest, incur costs to comply with 

new rules. The increase in costs to the well operators, and ultimately the Company, as a working 

interest owner, could include new or increased costs to install new emissions control equipment, 

operate and maintain existing equipment, obtain allowances to authorize greenhouse gas 

emissions and pay greenhouse gas related taxes. There also could be an adverse effect on demand 

for oil, NGL and natural gas in the market place.

Shortages of oilfield equipment, services, qualified personnel and resulting cost increases could 

adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field 

operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry 

can fluctuate significantly, often in correlation with oil, NGL and natural gas prices, causing periodic 

shortages. There have also been shortages of drilling rigs, hydraulic fracturing equipment and personnel 

and other oilfield equipment, as demand for rigs and equipment increased along with the number of wells 

being drilled. These factors also cause significant increases in costs for equipment, services and 

personnel. Higher oil, NGL and natural gas prices generally stimulate increased demand and result in 

increased prices for drilling rigs, crews and associated supplies, equipment and services. These shortages 

or price increases could adversely affect the Company’s profit margin, cash flow and operating results, or 

restrict its ability to drill wells and conduct ordinary operations.

Competition in the oil and natural gas industry is intense, and most of our competitors have 

greater financial and other resources than we do.

We compete in the highly competitive areas of oil and natural gas acquisition, development, 

exploration and production. We face intense competition from both major and independent oil and 

natural gas companies in seeking to acquire desirable producing properties, seeking new properties for 

future exploration and seeking the human resource expertise necessary to effectively develop properties. 

We also face similar competition in obtaining sufficient capital to maintain drilling rights in all drilling 

units.

A substantial number of our competitors have financial and other resources significantly greater 

than ours and some of them are fully integrated oil and natural gas companies. These companies are able 

to pay more for development prospects and productive oil and natural gas properties and are able to 

define, evaluate, bid for, purchase and subsequently drill a greater number of properties and prospects 

than our financial or human resources permit, effectively reducing our ability to participate in drilling on 

certain of our acreage as a working interest owner. Our ability to develop and exploit our oil and natural 

gas properties and to acquire additional quality properties in the future will depend upon our ability to 

successfully evaluate, select and acquire suitable properties and join in drilling with reputable operators 

in this highly competitive environment.

ITEM 1B UNRESOLVED STAFF COMMENTS

None
(12)

ITEM 2 PROPERTIES

At September 30, 2012, Panhandle’s principal properties consisted of (i) perpetual ownership of 

255,012 net mineral acres, held principally in Arkansas, New Mexico, North Dakota, Oklahoma, Texas 

and six other states; (ii) leases on 20,177 net acres primarily in Oklahoma: and (iii) working interests, 

royalty interests or both in 5,666 producing oil and natural gas wells and 62 wells in the process of being 

drilled or completed.

Consistent with industry practice, the Company does not have current abstracts or title opinions 

on all of its mineral properties and, therefore, cannot be certain that it has unencumbered title to all of 

these properties. In recent years, a few insignificant challenges have been made against the Company’s 

fee title to its properties.

The Company pays ad valorem taxes on minerals owned in ten states.

ACREAGE

Mineral Interests Owned

The following table of mineral interests owned reflects, in each respective state, the number of net 

and gross acres, net and gross producing acres, net and gross acres leased, and net and gross acres open 

(unleased) as of September 30, 2012.

(1) “Producing” represents the mineral acres in which Panhandle owns a royalty or working interest in a producing well.

(2) “Leased” represents the mineral acres owned by Panhandle that are leased to third parties but not producing.

(3) “Open” represents mineral acres owned by Panhandle that are not leased or in production.

Leases

The following table reflects net mineral acres leased from others, lease expiration dates, and net 

leased acres held by production as of September 30, 2012.

 Net Gross

 Net Gross Acres Acres Net

 Acres Acres Leased Leased Acres Gross Acres

 Net Producing Producing to Others to Others Open Open

State Acres Gross Acres (1) (1) (2) (2) (3) (3)

Arkansas 11,872 50,935 6,719 24,603 1,907 6,130 3,246 20,201

Colorado 8,217 39,080 224 447 7,993 38,633

Florida 3,832 8,212 3,832 8,212

Kansas 3,082 11,816 144 1,200 2,938 10,616

Montana 1,008 17,947 1,008 17,947

New Mexico 57,375 174,300 1,352 7,125 205 440 55,818 166,735

North Dakota 11,179 64,286 148 1,276 33 680 10,998 62,330

Oklahoma 113,399 950,832 39,751 322,635 4,645 32,320 69,003 595,796

South Dakota 1,825 9,300 1,825 9,300

Texas 43,196 360,025 7,933 70,781 244 5,285 35,019 283,959

Other 27 262 27 262

Total: 255,012 1,686,995 56,047 427,620 7,258 45,302 191,707 1,213,991
(13)

PROVED RESERVES

The following table summarizes estimates of proved reserves of oil, NGL and natural gas held by 

Panhandle as of September 30, 2012. All proved reserves are located onshore within the United States 

and are principally made up of small interests in 5,666 wells, predominately all of which are located in 

the Mid-Continent region. Other than this report, the Company’s reserve estimates are not filed with any 

other federal agency.

(1) 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve 

volumes disclosure. These NGL are associated with the rapid increase in drilling activity in 

western Oklahoma and the Texas Panhandle, which includes many plays (horizontal Granite 

Wash, Hogshooter Wash, Cleveland, Marmaton, Tonkawa and the Anadarko Basin Woodford 

Shale) producing significant volumes of NGL.

 The 13.0 Bcfe increase in total proved reserves from 2011 to 2012 is a combination of the following 

factors:

(1) Positive performance revisions of 3.6 Bcfe, of which 1.6 Bcfe were proved developed revisions 

principally attributable to properties in western Oklahoma. The remaining 2.0 Bcfe were proved 

undeveloped revisions principally attributable to higher proved reserves per well in the Company’s 

shale resource plays including the Fayetteville Shale, Southeastern Oklahoma Woodford Shale and 

the Anadarko Basin Woodford Shale.

 Barrels of Barrels of Mcf of

Net Proved Developed Reserves Oil NGL (1) Natural Gas Mcfe

September 30, 2012 849,548 494,160 65,733,119 73,795,367

September 30, 2011 759,989 386,774 60,193,878 67,074,456

September 30, 2010 861,240 - 57,344,190 62,511,630

Net Proved Undeveloped Reserves

September 30, 2012 222,771 294,582 47,780,937 50,885,055

September 30, 2011 83,749 404,874 41,644,106 44,575,844

September 30, 2010 63,769 - 40,826,265 41,208,879

Net Total Proved Reserves

September 30, 2012 1,072,319 788,742 113,514,056 124,680,422

September 30, 2011 843,738 791,648 101,837,984 111,650,300

September 30, 2010 925,009 - 98,170,455 103,720,509

 Net Acres

 Held by

State Net Acres Net Acres Expiring Production

2013 2014 2015 2016 2017

Arkansas 1,931 235 108 91 28 1,469

Kansas 2,117 2,117

Oklahoma 14,526 1,064 727 20 12,715

Other 1,603 1,603

TOTAL 20,177 1,299 835 111 0 28 17,904
(14)

(2) Negative pricing revisions (principally natural gas pricing) of 31.4 Bcfe, include 7.1 Bcfe of 

negative revisions due to proved developed wells reaching their economic limits earlier than 

previously projected resulting from current product prices. Negative revisions of 24.3 Bcfe were due 

to certain proved undeveloped locations, primarily in the Fayetteville Shale, Southeastern Oklahoma 

Woodford Shale and the Anadarko Basin Woodford Shale, becoming uneconomic at current product 

prices.

(3) Proved developed reserve additions of 7.8 Bcfe resulting from:

a) The Company’s ongoing development of conventional oil, NGL and natural gas plays 

 00 utilizing horizontal drilling, including the Granite Wash and Cleveland plays in western 

 00 Oklahoma and the Texas Panhandle, as well as the Marmaton and Tonkawa plays in western 

 00 Oklahoma. 

b) The Company’s ongoing development of unconventional natural gas plays utilizing horizontal 

 00 drilling, including the Arkansas Fayetteville Shale and, to a much lesser extent, the 

 00 Southeastern Oklahoma Woodford Shale.

c) The Company’s ongoing development of unconventional oil, NGL and natural gas plays 

 00 utilizing horizontal drilling in the Anadarko Basin Woodford Shale and Ardmore Basin 

 00 Woodford Shale in western and southern Oklahoma.

(4) PUD additions of 24.5 Bcfe principally in the Fayetteville Shale play in Arkansas and the Anadarko 

Basin Woodford Shale play in western Oklahoma.

(5) Property purchases of 19.1 Bcfe primarily in the Fayetteville Shale play in Arkansas.

(6) Production of 10.6 Bcfe.

The following details the changes in proved undeveloped reserves for 2012 (Mcfe):

The beginning PUD reserves were 44.6 Bcfe. A total of 5.4 Bcfe (12% of the beginning balance) 

were transferred to proved developed producing during 2012. An additional 24.3 Bcfe (55% of the 

beginning balance) were removed during 2012 as the result of becoming uneconomic at 2012 prices. A 

total of 29.7 Bcfe (67% of the beginning balance) of PUD reserves were moved out of the category 

during 2012 as either the result of being transferred to proved developed or removed as uneconomic. 

Only one PUD location from 2008, representing 1% of total 2012 PUD reserves remains in the PUD 

category while 45 PUD locations from 2009, representing 11% of total 2012 PUD reserves remain in the 

PUD category. The 46 PUD locations from 2008 and 2009 represent 8% of the Company’s current total 

of 589 PUD locations. We anticipate that all the Company’s PUD locations will be drilled and converted 

to PDP within five years of the date they were added. However, in the event that there are undrilled PUD 

locations at the end of the five-year period, it is our intent to remove the reserves associated with those 

locations from our proved reserves as revisions.

Beginning proved undeveloped reserves 44,575,844

Proved undeveloped reserves transferred to proved developed (5,393,421)

Revisions (22,369,152)

Extensions and discoveries 24,458,980

Purchases 9,612,804

Ending proved undeveloped reserves 50,885,055
(15)

The determination of reserve estimates is a function of testing and evaluating the production and 

development of oil and natural gas reservoirs in order to establish a production decline curve. The 

established production decline curves, in conjunction with oil and natural gas prices, development costs, 

production taxes and operating expenses, are used to estimate oil and natural gas reserve quantities and 

associated future net cash flows. As information is processed, over time, regarding the development of 

individual reservoirs and as market conditions change, estimated reserve quantities and future net cash 

flows will change as well. Estimated reserve quantities and future net cash flows are affected by changes 

in product prices. These prices have varied substantially in recent years and are expected to vary 

substantially from current pricing in the future. 

In January 2010, the FASB updated its oil and natural gas estimation and disclosure requirements 

to align its requirements with the SEC’s modernized oil and natural gas reporting rules, which were 

effective for annual reports on Form 10−K for fiscal years ending on or after December 31, 2009. The 

update included the following changes: (1) permitting use of new technologies to determine proved 

reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about 

reserve volumes; (2) enabling companies to additionally disclose their probable and possible reserves to 

investors, in addition to their proved reserves; (3) allowing previously excluded resources, such as oil 

sands, to be classified as oil and natural gas reserves rather than mining reserves; (4) requiring companies 

to report the independence and qualifications of a preparer or auditor, based on current Society of 

Petroleum Engineers criteria; (5) requiring the filing of reports for companies that rely on a third party to 

prepare reserve estimates or conduct a reserve audit; and (6) requiring companies to report oil and natural 

gas reserves using an average price based upon the prior 12-month period, rather than year-end 

prices. The update was applied prospectively as a change in accounting principle that is inseparable from 

a change in accounting estimate and was effective for entities with annual reporting periods ending on or 

after December 31, 2009. Effective September 30, 2010, the Company adopted the new requirements. 

See Note 11 to the financial statements in Item 8 – “Financial Statements and Supplementary Data” for 

disclosures regarding our oil and natural gas reserves. 

Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis 

of geoscience and engineering data, can be estimated with reasonable certainty to be economically 

producible – from a given date forward, from known reservoirs, and under existing economic conditions, 

operating methods, and government regulations – prior to the time at which contracts providing the right 

to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether 

deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons 

must have commenced, or the operator must be reasonably certain that it will commence the project 

within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified 

by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that 

can, with reasonable certainty, be judged to be continuous with it and to contain economically producible 

oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on 

fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a 

well penetration unless geoscience, engineering or performance data and reliable technology establishes a 

lower contact with reasonable certainty. Where direct observation from well penetrations has defined a 

highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves 

may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or 

performance data and reliable technology establish the higher contact with reasonable certainty. 

Reserves, which can be produced economically through application of improved recovery techniques 

(including, but not limited to, fluid injection), are included in the proved classification when: (i) 

successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the 

reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, 

or other evidence using reliable technology establishes the reasonable certainty of the engineering 

analysis on which the project or program was based; and (ii) the project has been approved for 

development by all necessary parties and entities, including governmental entities. Existing economic
(16)

conditions include prices and costs at which economic producibility from a reservoir is to be determined. 

The price shall be the average price during the 12-month period prior to the ending date of the period 

covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month 

price for each month within such period, unless prices are defined by contractual arrangements, 

excluding escalations based upon future conditions.

Developed oil and natural gas reserves are reserves of any category that can be expected to be 

recovered through existing wells with existing equipment and operating methods, or in which the cost of 

the required equipment is relatively minor compared to the cost of a new well, and through installed 

extraction equipment and infrastructure operational at the time of the reserve estimate, if the extraction is 

by means not involving a well. 

Undeveloped oil and natural gas reserves are reserves of any category that are expected to be 

recovered from new wells on undrilled acreage or from existing wells where a relatively major 

expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly 

offsetting development spacing areas that are reasonably certain of production when drilled, unless 

evidence using reliable technology exists that establishes reasonable certainty of economic producibility 

at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a 

development plan has been adopted indicating that they are scheduled to be drilled within five years, 

unless the specific circumstances justify a longer time. Under no circumstances shall estimates for 

undeveloped reserves be attributable to any acreage for which an application of fluid injection or other 

improved recovery technique is contemplated, unless such techniques have been proved effective by 

actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable 

technology establishing reasonable certainty.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of 

Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2012, 

2011 and 2010 (see Exhibits 23 and 99). 

The Company’s net proved oil, NGL and natural gas reserves (including certain undeveloped 

reserves described above) are located onshore in the United States. All studies have been prepared in 

accordance with regulations prescribed by the Securities and Exchange Commission. The reserve 

estimates were based on economic and operating conditions existing at September 30, 2012, 2011 and 

2010. Since the determination and valuation of proved reserves is a function of testing and estimation, the 

reserves presented should be expected to change as future information becomes available.

ESTIMATED FUTURE NET CASH FLOWS

Set forth below are estimated future net cash flows with respect to Panhandle’s net proved 

reserves (based on the estimated units set forth above in Proved Reserves) for the year indicated, and the 

present value of such estimated future net cash flows, computed by applying a 10% discount factor as 

required by SEC rules and regulations. As of September 30, 2010, the Company adopted the SEC Rule, 

Modernization of Oil and Gas Reporting Requirements. In accordance with the SEC rule, the estimated 

future net cash flows were computed using the 12-month average price calculated as the unweighted 

arithmetic average of the first-day-of-the-month individual product prices for each month within the 12-

month period prior to September 30 held flat over the life of the properties and applied to future 

production of proved reserves less estimated future development and production expenditures for these 

reserves. The amounts presented are net of operating costs and production taxes levied by the respective 

states. The Company reported NGL reserves for the first time in the 2011 year-end report. Increased 

drilling activity over the last two years in several western Oklahoma plays which produce significant 

NGL has resulted in meaningful NGL production and reserves for the Company, necessitating inclusion 

in the reserve calculation. Prices used for determining future cash flows from oil, NGL and natural gas as
(17)

of September 30, 2012 and 2011, were as follows: $89.41/Bbl, $35.70/Bbl, $2.51/Mcf ; $90.28/Bbl, 

$38.91/Bbl, $3.81/Mcf, respectively. Prices used for determining future cash flows from oil and natural 

gas as of September 30, 2010, were as follows: $69.23/Bbl, $4.33/Mcf. These future net cash flows based 

on SEC pricing rules should not be construed as the fair market value of the Company’s reserves. A 

market value determination would need to include many additional factors, including anticipated oil, 

NGL and natural gas price and production cost increases or decreases, which could affect the economic 

life of the properties.

OIL, NGL AND NATURAL GAS PRODUCTION

The following table sets forth the Company’s net production of oil, NGL and natural gas for the 

fiscal periods indicated.

(1) Natural gas production includes NGL volumes.

AVERAGE SALES PRICES AND PRODUCTION COSTS

The following tables set forth unit price and cost data for the fiscal periods indicated.

(1) Proceeds from the sale of NGL have been included in natural gas sales and are therefore 

 included in the price per Mcf of natural gas.

 Year Ended Year Ended Year Ended

Average Sales Price 9-30-12 9-30-11 (1) 9-30-10 (1)

Per Bbl, Oil $ 90.13 $ 88.00 $ 72.83

Per Bbl, NGL $ 33.23 * *

Per Mcf, Natural Gas $ 2.62 $ 4.13 $ 4.41

Per Mcfe $ 3.86 $ 4.87 $ 4.94

Estimated Future Net Cash Flows

 9-30-12 9-30-11 9-30-10

Proved Developed $ 165,036,044 $ 211,851,992 $ 202,056,455

Proved Undeveloped 72,851,862 91,232,949 84,200,597

Income Tax Expense 83,543,516 107,111,317 99,118,090

Total Proved $ 154,344,390 $ 195,973,624 $ 187,138,962

10% Discounted Present Value of Estimated Future Net Cash Flows

 9-30-12 9-30-11 9-30-10

Proved Developed $ 87,587,058 $ 106,464,138 $ 103,270,565

Proved Undeveloped 27,151,132 29,977,891 21,960,347

Income Tax Expense 47,323,902 58,059,595 52,730,503

Total Proved $ 67,414,288 $ 78,382,434 $ 72,500,409

 Year Ended Year Ended Year Ended

9-30-12 9-30-11 (1) 9-30-10 (1)

Bbls- Oil 153,143 104,141 102,379

Bbls- NGL 98,714 * *

Mcf- Natural Gas 9,072,298 8,297,657 8,302,342

Mcfe 10,583,440 8,922,503 8,916,616
(18)

* The Company reported NGL reserves for the first time in its 2011 year-end reserve report. Increased 

drilling activity over the last two years 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.

(1) Includes actual well operating costs, compression, handling and marketing fees paid on 

natural gas sales and other minor expenses associated with well operations. 

(2) Includes production taxes only. 

Approximately 30% of the Company’s oil, NGL and natural gas revenue is generated from 

royalty payments on its mineral acreage. Royalty interests bear no share of the operating costs on those 

producing wells.

GROSS AND NET PRODUCTIVE WELLS AND DEVELOPED ACRES

The following table sets forth Panhandle’s gross and net productive oil and natural gas wells as of 

September 30, 2012. Panhandle owns either working interests, royalty interests or both in these wells. 

The Company does not operate any wells.

Panhandle’s average interest in royalty interest only wells is 0.86%. Panhandle’s average interest 

in working interest wells is 5.14% working interest and 4.97% net revenue interest.

Information on multiple completions is not available from Panhandle’s records, but the number is 

not believed to be significant.

As of September 30, 2012, Panhandle owned 427,620 gross developed mineral acres and 56,047 

net developed mineral acres. Panhandle has also leased from others 135,526 gross developed acres 

containing 17,904 net developed acres.

UNDEVELOPED ACREAGE

As of September 30, 2012, Panhandle owned 1,259,293 gross and 198,965 net undeveloped 

mineral acres, and leases on 19,852 gross and 2,273 net undeveloped acres.

 Year Ended Year Ended Year Ended

Average Production (lifting costs) 9-30-12 9-30-11 9-30-10

(Per Mcfe)

Well Operating Costs (1) $ 0.86 $ 0.95 $ 0.92

Production Taxes (2) 0.14 0.16 0.16

$ 1.00 $ 1.11 $ 1.08

Gross Working Net Working Gross Royalty Total Gross

Interest Wells Interest Wells Only Wells Wells

Oil 206 14.89 937 1,143

Natural Gas 1,648 80.42 2,875 4,523

Total 1,854 95.31 3,812 5,666
(19)

DRILLING ACTIVITY

The following net productive development, exploratory and purchased wells and net dry 

development, exploratory and purchased wells in which the Company had either a working interest, a 

royalty interest or both were drilled and completed during the fiscal years indicated.

PRESENT ACTIVITIES

The following table sets forth the gross and net oil and natural gas wells drilling or testing as of 

September 30, 2012, in which Panhandle owns either a working interest, a royalty interest or both. These 

wells were not producing at September 30, 2012.

OTHER FACILITIES

The Company has a lease on 12,369 square feet for its office in Oklahoma City, Oklahoma, which 

ends April 30, 2015.

SAFE HARBOR STATEMENT

This report, including information included in, or incorporated by reference from, future filings 

by the Company with the SEC, as well as information contained in written material, press releases and 

oral statements, contains, or may contain, certain statements that are “forward-looking statements,”

 Net Productive Net Productive

Development Wells Working Interest Wells Royalty Interest Wells Net Dry Wells

Fiscal years ended:

 September 30, 2012 5.376408 1.225832 0.093438

 September 30, 2011 2.573391 0.907650 0.062188

 September 30, 2010 2.953777 0.868179 0.057282

Exploratory Wells

Fiscal years ended:

 September 30, 2012 0.298974 0.090654 0.531250

 September 30, 2011 0.510643 0.372957 0.007813

 September 30, 2010 0.029688 0.338320 -- 0 --

Purchased Wells

Fiscal years ended:

 September 30, 2012 4.300626 0.231430 -- 0 --

 September 30, 2011 -- 0 -- 0.235058 -- 0 --

 September 30, 2010 -- 0 -- -- 0 -- -- 0 --

 Gross Wells Net Wells

Oil 6 0.18

Natural Gas 56 2.00
(20)

within the meaning of the federal securities laws. All statements, other than statements of historical facts, 

included or incorporated by reference in this report, which address activities, events or developments 

which are expected to, or anticipated will, or may, occur in the future, are forward-looking statements. 

The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts” and similar 

expressions are used to identify forward-looking statements. 

These forward-looking statements include, among others, such things as: the amount and nature 

of our future capital expenditures; wells to be drilled or reworked; prices for oil, NGL and natural gas; 

demand for oil, NGL and natural gas; estimates of proved oil, NGL and natural gas reserves; 

development and infill drilling potential; drilling prospects; business strategy; production of oil, NGL and 

natural gas reserves; and expansion and growth of our business and operations. 

These statements are based on certain assumptions and analyses made by the Company in light of 

experience and perception of historical trends, current conditions and expected future developments as 

well as other factors believed appropriate in the circumstances. However, whether actual results and 

development will conform to our expectations and predictions is subject to a number of risks and 

uncertainties, which could cause actual results to differ materially from our expectations.

One should not place undue reliance on any of these forward-looking statements. The Company 

does not currently intend to update forward-looking information and to release publicly the results of any 

future revisions made to forward-looking statements to reflect events or circumstances, which reflect the 

occurrence of unanticipated events, after the date of this report.

In order to provide a more thorough understanding of the possible effects of some of these 

influences on any forward-looking statements made, the following discussion outlines certain factors that 

in the future could cause results for 2013 and beyond to differ materially from those that may be 

presented in any such forward-looking statement made by or on behalf of the Company.

Commodity Prices. The prices received for oil, NGL and natural gas production have a direct 

impact on the Company’s revenues, profitability and cash flows as well as the ability to meet its 

projected financial and operational goals. The prices for crude oil, NGL and natural gas are dependent on 

a number of factors beyond the Company’s control, including: the demand for oil, NGL and natural gas; 

weather conditions in the continental United States (which can greatly influence the demand for natural 

gas at any given time as well as the price we receive for such natural gas); and the ability of current 

distribution systems in the United States to effectively meet the demand for oil, NGL and natural gas at 

any given time, particularly in times of peak demand which may result because of adverse weather 

conditions.

Oil prices are sensitive to foreign influences based on political, social or economic factors, any 

one of which could have an immediate and significant effect on the price and supply of oil. In addition, 

prices of both natural gas and oil are becoming more and more influenced by trading on the commodities 

markets, which has, at times, increased the volatility associated with these prices.

Uncertainty of Oil, NGL and Natural Gas Reserves. There are numerous uncertainties inherent 

in estimating quantities of proved reserves and their values, including many factors beyond the 

Company’s control. The oil, NGL and natural gas reserve data included in this report represents only an 

estimate of these reserves. Oil and natural gas reservoir engineering is a subjective and inexact process of 

estimating underground accumulations of oil, NGL and natural gas that cannot be measured in an exact 

manner. Estimates of economically recoverable oil, NGL and natural gas reserves depend on a number of 

variable factors, including historical production from the area compared with production from other 

producing areas and assumptions concerning future oil, NGL and natural gas prices, future operating 

costs, severance and excise taxes, development costs, and workover and remedial costs.
(21)

Some or all of these assumptions may vary considerably from actual results. For these reasons, 

estimates of the economically recoverable quantities of oil, NGL and natural gas and estimates of the 

future net cash flows from oil, NGL and natural gas reserves prepared by different engineers or by the 

same engineers but at different times may vary substantially. Accordingly, oil, NGL and natural gas 

reserve estimates may be subject to periodic downward or upward adjustments. Actual production, 

revenues and expenditures with respect to oil, NGL and natural gas reserves will vary from estimates, 

and those variances can be material.

The Company does not operate any of the properties in which it has an interest and has very 

limited ability to exercise influence over operations for these properties or their associated costs. 

Dependence on the operator and other working interest owners for these projects and the limited ability 

to influence operations and associated costs could materially and adversely affect the realization of 

targeted returns on capital in drilling or acquisition activities and targeted production growth rates.

The information regarding discounted future net cash flows included in this report is not 

necessarily the current market value of the estimated oil, NGL and natural gas reserves attributable to the 

Company’s properties. As required by the SEC, the estimated discounted future net cash flows from 

proved oil, NGL and natural gas reserves are determined based on the fiscal year’s 12-month average of 

the first-day-of-the-month individual product prices and costs as of the date of the estimate. Actual future 

prices and costs may be materially higher or lower. Actual future net cash flows are also affected, in part, 

by the amount and timing of oil, NGL and natural gas production, supply and demand for oil, NGL and 

natural gas and increases or decreases in consumption. 

In addition, the 10% discount factor required by the SEC used in calculating discounted future net 

cash flows for reporting purposes is not necessarily the most appropriate discount factor based on interest 

rates in effect from time to time and the risks associated with operations of the oil and natural gas 

industry in general.

ITEM 3 LEGAL PROCEEDINGS

There were no material legal proceedings involving Panhandle on September 30, 2012, or at the 

date of this report.

ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of Panhandle’s security holders during the fourth quarter of 

the fiscal year ended September 30, 2012.
(22)

PART II

ITEM 5 MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND 

 UNREGISTERED SALES OF EQUITY SECURITIES

The above graph compares the 5-year cumulative total return provided shareholders on our Class 

A Common Stock (“Common Stock”) relative to the cumulative total returns of the S&P Smallcap 600 

Index and the S&P Oil & Gas Exploration & Production Index. An investment of $100 (with 

reinvestment of all dividends) is assumed to have been made in our Common Stock and in each of the 

indexes on September 30, 2007, and its relative performance is tracked through September 30, 2012.

Since July 22, 2008, the Company’s Common Stock has been listed and traded on the New York 

Stock Exchange (symbol PHX). The following table sets forth the high and low trade prices of the 

Common Stock during the periods indicated:
(23)

At November 26, 2012, there were 1,539 holders of record of Panhandle’s Class A Common 

Stock and approximately 3,900 beneficial owners.

During the past two years, the Company has paid quarterly dividends of $.07 per share on its 

Common Stock. Approval by the Company’s Board is required before the declaration and payment of 

any dividends.

While the Company anticipates it will continue to pay dividends on its Common Stock, the 

payment and amount of future cash dividends will depend upon, among other things, financial condition, 

funds from operations, the level of capital and development expenditures, future business prospects, 

contractual restrictions and any other factors considered relevant by the Board.

The Company’s credit facility also contains a provision limiting the paying or declaring of a cash 

dividend to 15% of net cash flow provided by operating activities from the Statement of Cash Flows of 

the preceding 12-month period. See Note 4 to the financial statements in Item 8 – “Financial Statements 

and Supplementary Data” for a further discussion of the credit facility.

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 

2010, the Board 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 Board’s approval included an initial 

authorization to purchase up to $1.5 million of Common Stock, with a provision for subsequent 

authorizations without specific action by the Board. As the amount of Common Stock purchased under 

any authorization reaches $1.5 million, another $1.5 million is automatically authorized for Common 

Stock purchases unless the Board determines otherwise. Pursuant to these resolutions adopted by the 

Board, the purchase of additional $1.5 million increments of the Company’s Common Stock became 

authorized and approved effective March 29, 2011, and March 14, 2012. The shares are held in treasury 

and are accounted for using the cost method. There were no Common Stock purchases in the fourth 

quarter of fiscal year 2012. At September 30, 2012, and September 30, 2011, 10,660 and 10,710 

(respectively) treasury shares were contributed to the Company’s ESOP on behalf of the ESOP 

participants.

Quarter Ended High Low

December 31, 2010 $ 28.70 $ 23.75

March 31, 2011 $ 31.88 $ 25.60

June 30, 2011 $ 32.50 $ 27.30

September 30, 2011 $ 36.25 $ 26.36

December 31, 2011 $ 36.00 $ 26.18

March 31, 2012 $ 33.74 $ 28.05

June 30, 2012 $ 30.57 $ 24.16

September 30, 2012 $ 33.49 $ 27.85
(24)

 As of and for the year ended September 30,

2012 2011 2010 2009 2008

Revenues

Oil, NGL and natural gas sales $ 40,818,434 $ 43,469,130 $ 44,068,947 $ 37,421,688 $ 69,026,785

Lease bonuses and rentals 7,152,991 352,757 1,120,674 188,906 167,559

Gains (losses) on derivative contracts 73,822 734,299 6,343,661 (661,828) (940,823)

Income from partnerships 487,070 420,465 405,134 323,848 631,891

48,532,317 44,976,651 51,938,416 37,272,614 68,885,412

Costs and expenses

Lease operating expense 9,141,970 8,441,754 8,193,319 7,696,026 6,629,170

Production taxes 1,449,537 1,456,755 1,446,545 1,201,209 3,426,592

Exploration costs 979,718 1,025,542 1,583,773 711,582 455,943

Depr., depl. and amortization (DD&A) 19,061,239 14,712,188 19,222,123 28,168,933 19,784,660

Provision for impairment 826,508 1,728,162 605,615 2,464,520 526,380

Loss (gain) on asset sales, mt. & other 39,493 (68,325) (1,028,148) (2,677,407) 14,826

Gen. and administrative 6,388,856 5,994,663 5,594,499 4,866,044 5,006,512

Bad debt expense (recovery) - - - (185,272) 591,258

37,887,321 33,290,739 35,617,726 42,245,635 36,435,341

Income (loss) before provision

(benefit) for income taxes 10,644,996 11,685,912 16,320,690 (4,973,021) 32,450,071

Provision (benefit) for income taxes 3,274,000 3,192,000 4,901,000 (2,568,000) 10,894,302

Net income (loss) $ 7,370,996 $ 8,493,912 $ 11,419,690 $ (2,405,021) $ 21,555,769

Basic and diluted earnings (loss) per share $ 0.88 $ 1.01 $ 1.36 $ (0.29) $ 2.54

Dividends declared per share $ 0.28 $ 0.28 $ 0.28 $ 0.28 $ 0.28

Weighted average shares outstanding

Basic and diluted 8,360,931 8,393,890 8,422,387 8,397,337 8,492,378

Net cash provided by (used in):

Operating activities $ 25,371,195 $ 29,283,929 $ 27,806,475 $ 37,710,606 $ 40,063,896

Investing activities $ 38,288,959 $ (27,200,816) $ (9,845,516) $ (36,322,992) $ (37,846,172)

Financing activities $ 11,394,864 $ (4,173,372) $(13,003,609) $ (1,643,414) $ (2,311,376)

Total assets $ 135,186,730 $ 111,424,193 $105,124,839 $108,549,632 $ 122,007,183

Long term debt $ 14,874,985 $ - $ - $ 10,384,722 $ 9,704,100

Shareholders’ equity $ 83,852,146 $ 78,802,317 $ 73,581,996 $ 64,122,343 $ 68,348,901

ITEM 6 SELECTED FINANCIAL DATA

The following table summarizes financial data of the Company for its last five fiscal years and 

should be read in conjunction with Item 7 – “Management’s Discussion and Analysis of Financial 

Condition and Results of Operations” and the Financial Statements of the Company, including the Notes 

thereto, included elsewhere in this report.

ITEM 7 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION 

 AND RESULTS OF OPERATIONS

BUSINESS OVERVIEW

The Company’s principal line of business is to explore for, develop, produce and sell oil, NGL 

and natural gas. Results of operations are dependent primarily upon: reserve quantities and associated 

exploration and development costs in finding new reserves; production quantities and related production 

costs; and oil, NGL and natural gas sales prices. In the 2012 first quarter the Company acquired certain 

assets in the core of the Fayetteville Shale which included an average working interest of 2.3% in 193 

producing non-operated natural gas wells and 1,531 acres of leasehold containing approximately 240
(25)

future infill drilling locations. This acquisition contributed to both increased drilling activity and 

increased natural gas production during 2012. During 2012, net wells drilled increased 69% over net 

wells drilled in 2011. However, capital expenditures only increased approximately 11% due to the 

average drilling and completion cost per well being lower in 2012 than in 2011. The lower drilling cost 

per well is primarily the result of drilling more wells in the Arkansas Fayetteville Shale during 2012 and 

less wells in the Anadarko Woodford Shale play where a typical well costs two and one half to three 

times that of a typical Fayetteville Shale well.

Natural gas production was 9% higher in 2012 than in 2011. This production increase is the 

combined effect of added natural gas production from Fayetteville Shale acquisitions and continued 

drilling on the Company’s mineral and leasehold acreage.

Ongoing development in the following oily plays has resulted in a 47% increase in 2012 oil 

production, as compared to 2011:

• Horizontal Granite Wash 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

• Vertical Mississippian in northern Oklahoma

• Vertical Spraberry in West Texas

• Vertical Yeso in southeastern New Mexico

• Horizontal Anadarko Basin Woodford Shale in western Oklahoma

• Horizontal Ardmore Basin Woodford Shale in southern Oklahoma

As of September 30, 2012, the Company owned an average 3.6% net revenue interest in 62 wells 

that were drilling or testing. As these wells begin producing and other scheduled wells are drilled and 

completed in the abovementioned plays, the Company expects fiscal 2013 oil and natural gas production 

to increase over that of 2012.

Although oil, NGL and natural gas production increased in 2012, oil, NGL and natural gas sales 

revenues decreased 6% as a result of sharply lower natural gas prices, partially offset by a slight increase 

in oil prices. Based on recent forward strip pricing for 2013, the Company expects average natural gas 

prices to be higher and average oil prices to be slightly lower than the average prices of 2012.

The Company’s proved developed oil, NGL and natural gas reserves increased in 2012, compared 

to 2011, by 6.7 Bcfe. The increase is due to the Fayetteville Shale acquisitions and successful drilling of 

exploratory and developmental wells (in excess of PUD reserves previously presented), partially offset 

by negative natural gas pricing revisions. The overall increase in oil, NGL and natural gas production 

combined with the negative price revisions to 2012 proved developed natural gas reserves and higher 

finding cost experienced in the oil and liquids-rich areas resulted in higher DD&A in 2012.

Management currently expects drilling on the Company’s acreage to result in capital expenditures 

for oil and natural gas activities of approximately $25 million during 2013. The Company will also 

continue to evaluate opportunities to acquire mineral acreage or producing properties. Acquisitions, if 

any, will be financed by a combination of cash flows and the bank credit facility.

The Company had no off balance sheet arrangements during 2012 or prior years.

The following table reflects certain operating data for the periods presented:
(26)

RESULTS OF OPERATIONS

Fiscal Year 2012 Compared to Fiscal Year 2011

Overview

The Company recorded net income of $7,370,996, or $0.88 per share, in 2012, compared to net 

income of $8,493,912, or $1.01 per share, in 2011. Revenues increased in 2012 primarily due to 

increased lease bonuses and higher oil and natural gas sales volumes, partially offset by lower natural gas 

prices.

Expenses increased due to higher DD&A, LOE and G&A in 2012, partially offset by decreases in 

the provision for impairment and exploration costs. Significant well additions through acquisition and 

drilling in 2012 increased production volumes and lifting costs, resulting in higher DD&A and LOE in 

2012.

Oil, NGL and Natural Gas Sales

Oil, NGL and natural gas sales revenues decreased $2,650,696 or 6% for 2012, as compared to 

2011. The decrease was due to lower natural gas prices of 37%, partially offset by increased oil volumes 

of 47%, increased natural gas volumes of 9% and a 2% increase in oil prices in 2012. 

The oil production increase is due to continued drilling in western Oklahoma oily plays such as 

the horizontal Granite Wash, Cleveland, Tonkawa, Marmaton, Anadarko Basin Woodford Shale and 

other plays in Oklahoma, West Texas, Texas Panhandle and southeastern New Mexico. The natural gas 

production increase is mainly a result of production attributable to the acquisition in the Fayetteville

(1) Proceeds from the sale of NGL in 2011 and 2010 were included in natural gas sales, and were 

therefore included in the price per Mcf of natural gas.

* The Company reported NGL reserves for the first time in its 2011 year-end reserve report. 

Increased drilling activity over the last two years 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.

 For the Year Ended September 30,

 Percent Percent

2012 Incr. or (Decr.) 2011 Incr. or (Decr.) 2010

Production:

Oil (Bbls) 153,143 47% 104,141 2% 102,379

NGL (Bbls) 98,714 - * - *

Natural Gas (Mcf) 9,072,298 9% 8,297,657 0% 8,302,342

Mcfe 10,583,440 19% 8,922,503 0% 8,916,616

Average Sales Price:

Oil (per Bbl) $ 90.13 2% $ 88.00 21% $ 72.83

NGL (per Bbl) $ 33.23 - * - *

Natural Gas (Mcf) (1) $ 2.62 -37% $ 4.13 -6% $ 4.41

Mcfe $ 3.86 -21% $ 4.87 -1% $ 4.94
(27)

Shale in Arkansas that the Company completed effective October 25, 2011. As of September 30, 2012, 

the Company owned an average 3.6% net revenue interest in 62 wells that were drilling or testing.

Production by quarter for 2012 and 2011 was as follows:

Lease Bonus and Rentals

Lease bonuses and rentals increased $6,800,234 in 2012. The increase was mainly due to the 

Company leasing 2,743 net mineral acres in Roger Mills County, Oklahoma, for $4.8 million. 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 mineral acres in the horizontal Mississippian play in 

northern Oklahoma for $1.7 million. There were no large leases of the Company’s mineral acreage in 

2011.

Gains (Losses) on Derivative Contracts

Realized and unrealized gains and losses are scheduled below:

The decrease in gains was mainly due to the natural gas basis protection swaps being less 

beneficial in 2012, as the basis differentials between NYMEX and CEGT and PEPL declined 

significantly. As of September 30, 2012, the Company’s natural gas basis protection swaps have 

expiration dates of December 2012; the natural gas costless collar contracts have expiration dates of 

October 2012 and January 2013; the oil costless collar contracts have expiration dates of December 2012.

Lease Operating Expenses (LOE) and Production Taxes

LOE increased $700,216 or 8% in 2012. LOE costs per Mcfe of production decreased from $.95 

in 2011 to $.86 in 2012. The total LOE increase is primarily related to increased field operating costs of 

$487,388 in 2012 compared to 2011. Field operating costs increased mainly due to the large addition of 

wells through acquisition and drilling in 2012. Field operating costs were $.42 per Mcfe in 2012 

compared to $.44 per Mcfe in 2011, a 5% decrease. This decrease in rate is principally the result of fewer 

well workovers performed in 2012.

The increase in LOE related to field operating costs was also coupled with an increase in handling 

fees (primarily gathering, transportation and marketing costs) on natural gas of $212,828 in 2012, as 

compared to 2011. On a per Mcfe basis, these fees were down $.06 due to lower natural gas prices and 

the addition of significant oil production, which is unencumbered by these fees. Handling fees are mainly

Gains (Losses) on

Derivative Contracts 2012 2011

Realized $ 462,033 $ 2,138,685

Unrealized (388,211) (1,404,386)

Total $ 73,822 $ 734,299

 2012 2011

First quarter 2,559,524 Mcfe 2,208,218 Mcfe

Second quarter 2,654,485 Mcfe 2,152,011 Mcfe

Third quarter 2,649,351 Mcfe 2,129,160 Mcfe

Fourth quarter 2,720,080 Mcfe 2,433,114 Mcfe

Total 10,583,440 Mcfe 8,922,503 Mcfe
(28)

charged as a percent of natural gas sales but can also be charged based on natural gas production 

volumes.

Exploration Costs

Exploration costs were $979,718 in 2012 compared to $1,025,542 in 2011, a $45,824 decrease. 

During 2012, leasehold impairment and expired leasehold totaled $377,942 compared to $482,491 during 

2011, a $104,549 decrease. The decline was driven by lower provisions for expected lease expirations in 

2012, as compared to 2011. Charges on three exploratory dry holes totaled $601,776 during 2012; 

whereas, in 2011 the Company incurred exploratory dry hole costs on two wells totaling $543,051.

Depreciation, Depletion and Amortization (DD&A)

DD&A increased $4,349,051 or 30% in 2012. DD&A per Mcfe was $1.80 in 2012 compared to 

$1.65 in 2011. DD&A increased $2,738,695 due to oil, NGL and natural gas production volumes 

increasing 19% in the 2012 period compared to the 2011 period. The remaining increase of $1,610,356 

was caused by a $.15 increase in the DD&A rate. This rate increase is mainly due to negative price 

revisions reducing ultimate reserves on a significant number of wells in reserves reported at September 

30, 2012, as well as higher finding cost experienced in oil and liquids-rich areas where the Company is 

drilling and has had new wells come on line.

Provision for Impairment

The provision for impairment decreased $901,654 in 2012, as compared to 2011. During 2012, 

impairment of $826,508 was recorded on twelve small fields in Oklahoma. These fields have one to a 

few wells and are more susceptible to impairment when a well in the field experiences downward reserve 

revisions, or when a newly completed well with little production history is added to one of these 

fields. During the 2011 period, impairment of $1,728,162 was recorded on nine small fields in Oklahoma 

and Texas.

General and Administrative Costs (G&A)

G&A increased $394,193 or 7% in 2012. The increase is primarily related to increases in the 

following expense categories: personnel $419,166 and legal fees $118,245. These were partially offset by 

decreases in technical consulting, Board fees, company insurance and other expenses of $143,218 in 

2012. The increase in 2012 personnel related expenses was the result of additional employees and annual 

increases in salaries and bonuses totaling $206,806, restricted stock expense increase of $178,441 and 

higher ESOP expense of $25,475. The increase in legal expenses resulted from increased acquisition 

activity and a quiet title defense settlement in 2012.

Provision (Benefit) for Income Taxes

The 2012 provision for income taxes of $3,274,000 was based on a pre-tax income of 

$10,644,996, as compared to a provision for income taxes of $3,192,000 in 2011, based on a pre-tax 

income of $11,685,912. The effective tax rate for 2012 was 31%, compared to an effective tax rate for 

2011 of 27%. The 2012 effective tax rate increase of 4% was due to increased state income taxes of 

$553,926, partially offset by an excess percentage depletion benefit increase of $112,524. The 2012 state 

income tax increase was a result of significantly higher lease bonus income in Oklahoma, combined with 

lower intangible drilling cost deductions from Oklahoma taxable income. The Company’s utilization of 

excess percentage depletion (which is a permanent tax benefit) decreases the provision for income taxes. 

The benefit of excess percentage depletion is not directly related to the amount of recorded income or
(29)

loss. Accordingly, in cases where the recorded income or loss is relatively small, the proportional effect 

of the excess percentage depletion on the effective tax rate may become significant. 

Fiscal Year 2011 Compared to Fiscal Year 2010

Overview

The Company recorded net income of $8,493,912, or $1.01 per share, in 2011, compared to net 

income of $11,419,690, or $1.36 per share, in 2010. Decreased revenues in 2011 were primarily due to 

lower realized and unrealized gains on derivative contracts and lower lease bonuses and rentals. Actual 

and forward looking prices were lower than the Company’s derivative contracts during 2011, resulting in 

net gains on derivative contracts; however, the variation during 2011 was not as significant as in 2010, 

therefore, gains on derivative contracts during 2011 were significantly less. The renewal of leases on 

certain of the Company’s Arkansas undeveloped mineral acreage generated significant lease bonuses 

during 2010; whereas there were no such renewals in 2011.

Expenses decreased due to lower DD&A and exploration costs in 2011, partially offset by 

increases in the provision for impairment, general and administrative costs and a decrease in gain on asset 

sales, interest and other. The positive performance revisions recognized in the reserves reported at 

September 30, 2010, resulted in lower 2011 DD&A.

Oil and Natural Gas Sales

Oil and natural gas sales revenues decreased $599,817 or 1% for 2011, as compared to 2010. A 

decline in natural gas prices of 6% from 2010 to 2011, partially offset by a 21% increase in oil prices in 

2011, caused the reduction of oil and natural gas sales revenues. Production from wells that came on line 

in 2011 offset the natural decline of existing wells such that oil and natural gas production volume in 

2011 was relatively flat compared to 2010 volumes. 

Drilling activity increased during the last quarter of 2010 and continued at a much higher rate 

throughout 2011, as compared to the first nine months of fiscal 2010. This increase in drilling activity 

resulted in 2011 production volumes (on an Mcfe basis) that were flat compared to those of 2010. The 

increased drilling activity is primarily on the Company’s mineral acreage in the Arkansas Fayetteville 

Shale and in the oil and natural gas liquids-rich plays such as the Anadarko Woodford Shale, Horizontal 

Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Tonkawa and other similar plays in western 

Oklahoma. As of September 30, 2011, the Company owned an average 2.6% net revenue interest in 48 

wells that were drilling or testing.

Production by quarter for 2011 and 2010 was as follows:

Lease Bonus and Rentals

Lease bonus and rentals decreased $767,917 for 2011, as compared to 2010. Lease bonus and 

rental revenues in 2010 included lease bonuses of approximately $723,000 from certain of the

 2011 2010

First quarter 2,208,218 Mcfe 2,278,133 Mcfe

Second quarter 2,152,011 Mcfe 2,090,154 Mcfe

Third quarter 2,129,160 Mcfe 2,236,236 Mcfe

Fourth quarter 2,433,114 Mcfe 2,312,093 Mcfe

Total 8,922,503 Mcfe 8,916,616 Mcfe
(30)

Company’s Arkansas mineral acreage, whereas there were no large leases of Company acreage in 2011.

Gains (Losses) on Derivative Contracts

Realized and unrealized gains and losses are scheduled below:

The Company’s natural gas fixed price swap contracts had expiration dates of October 2011; the 

oil costless collar contracts have expiration dates of December 2011; the natural gas basis protection 

swaps have expiration dates of December 2011 and December 2012.

Lease Operating Expenses (LOE) and Production Taxes

LOE increased $248,435 or 3% in 2011. LOE costs per Mcfe of production increased from $.92 

in 2010 to $.95 in 2011. The total LOE increase and the LOE per Mcfe increase were primarily related to 

increased field operating costs of approximately $276,000 in 2011 compared to 2010. Field operating 

costs were $.44 per Mcfe in 2011 compared to $.41 per Mcfe in 2010, a 7% increase. These increases 

were principally the result of well workovers performed in 2011.

Handling fees (primarily gathering, transportation and marketing costs) on natural gas in 2011 

were slightly less than those of 2010. These fees decreased LOE approximately $28,000 in 2011.

Production taxes increased $10,210 or 1% in 2011. Some wells previously eligible for production 

tax credits or reductions, primarily in Oklahoma and Arkansas, lost their eligibility during 2011 due to 

meeting either time or payout thresholds stipulated in Oklahoma and Arkansas production tax laws.

Exploration Costs

Exploration costs were $1,025,542 in 2011 compared to $1,583,773 in 2010, a $558,231 decrease. 

During 2011, leasehold impairment and expired leasehold totaled $482,491 compared to $1,191,598 

during 2010, a $709,107 decrease. The decline was driven by lower provisions for expected lease 

expirations in 2011, as compared to 2010. Charges on two exploratory dry holes totaled $543,051 during 

2011; whereas, in 2010 the Company incurred minor exploratory dry hole costs totaling $4,541. During 

2010, $387,634 was charged to exploration costs related to geological and geophysical costs paid upon 

the execution of a joint exploration agreement with a privately held independent operator to explore for 

oil in eastern Oklahoma.

Depreciation, Depletion and Amortization (DD&A)

Total DD&A decreased $4,509,935 or 24% in 2011, while DD&A per Mcfe decreased to $1.65 in 

2011, as compared to $2.16 in 2010. The DD&A decrease was attributable to the $.51 decline in the 

DD&A rate per Mcfe. This rate decline in 2011 was due to the positive performance revisions recognized 

in the reserves reported at September 30, 2010.

Gains (Losses) on

Derivative Contracts 2011 2010

Realized $ 2,138,685 $ 2,209,900

Unrealized (1,404,386) 4,133,761

Total $ 734,299 $ 6,343,661
(31)

Provision for Impairment

The provision for impairment increased $1,122,547 in 2011, as compared to 2010. During 2011, 

impairment of $1,728,162 was recorded on nine small fields in Oklahoma and Texas. These fields had 

few wells and are more susceptible to impairment when a well in the field experiences downward reserve 

revisions, or when a newly completed well with little production history is added to one of these fields. 

On one of these fields, a new material well began production on September 27, 2011. The well’s early 

production was significantly impacted by the recovery of large volumes of water utilized in the fracture 

treatment. Since the well’s early production had been low, while at the same time producing large 

volumes of load water, the calculated reserves and future net cash flows were calculated to be 

significantly less than was previously attributed to the well, resulting in a material impairment to the field 

of $590,629. Wells such as this are subject to performance revisions going forward as more is known of 

their production history and pattern. During the 2010 period, impairment of $605,615 was recorded on 

six small fields.

Included in the 2011 total above, was an impairment charge of $716,448 on the Joiner City 

prospect, a horizontal Woodford Shale prospect in the oil and natural gas liquids-rich Marietta Basin in 

southern Oklahoma. The first well was drilled and completed during the first quarter of 2011 and is 

currently producing commercial quantities of oil and natural gas. As of September 30, 2011, this well had 

a net book value of $503,960 after impairment. Costs on this well were extraordinarily high due to this 

well being the first and only horizontal well drilled in the field.

Loss (Gain) on Asset Sales, Interest and Other

In 2010, the Company received $1,124,682 from the settlement of a lawsuit related to one well in 

western Oklahoma. No interest expense was incurred during 2011, compared to interest expense of 

$60,912 recorded in 2010.

General and Administrative Costs (G&A)

G&A increased $400,164 or 7% in 2011. The increase was primarily related to increases in the 

following expense categories: personnel $346,331; Board fees $92,674; computer consulting fees 

$20,000; and reservoir engineering fees $71,000. The above were partially offset by a decrease in legal 

fees of $228,837 in 2011. The increase in 2011 personnel related expenses was the result of annual 

increases in salaries and bonuses totaling approximately $113,000, a restricted stock expense increase of 

$140,454, a rise in employee insurance costs of $22,713 and higher ESOP expense of $20,220. The 

increase in Board fees resulted from the addition of one director in May 2010 (resulting in partial year 

retainer and meeting fees during 2010, but a full year’s fees during 2011) combined with increases in 

annual retainer fees and meeting fees paid to directors during 2011.

Non-recurring legal fees of approximately $230,000 were expensed during 2010 related to a 

lawsuit on one well in western Oklahoma and to the 2008 bankruptcy of SemGroup, L.P., which owed 

the Company for crude oil they had purchased.

Provision (Benefit) for Income Taxes

The 2011 provision for income taxes of $3,192,000 was based on a pre-tax income of 

$11,685,912, as compared to a provision for income taxes of $4,901,000 in 2010, based on a pre-tax 

income of $16,320,690. Income taxes in 2010 were reduced by the removal of the $278,000 valuation 

allowance on Oklahoma NOLs which reduced the effective tax rate by 2%. The effective tax rate for 

2011 was 27%, compared to an effective tax rate for 2010 of 30%. The Company’s utilization of excess 

percentage depletion (which is a permanent tax benefit) decreases the provision for income taxes. The
(32)

benefit of excess percentage depletion is not directly related to the amount of recorded income or loss. 

Accordingly, in cases where the recorded income or loss is relatively small, the proportional effect of the 

excess percentage depletion on the effective tax rate may become significant.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2012, the Company had positive working capital of $3,995,103, as compared to 

positive working capital of $7,314,096 at September 30, 2011. 

Liquidity

Cash and cash equivalents were $1,984,099 as of September 30, 2012, compared to $3,506,999 at 

September 30, 2011, a decrease of $1,522,900. Cash flows for the 12 months ended September 30 are 

summarized as follows:

Operating activities:

The decrease of $3,912,734 in cash provided by operating activities is primarily the effect 

of the following:

Decreased collections of oil, NGL and natural gas sales (net of withheld 

production taxes and handling fees) for the 2012 period compared to the 2011 

period resulted in less cash provided by operating activities of $2,436,566.

Realized gains on derivative contracts decreased $1,676,652 in 2012, as compared 

 to 2011. 

Income tax payments in 2012 were $1,356,706 compared to payments of 

$2,584,172 in 2011, a decrease of $1,227,466. 

Cash expenditures for lease operating expenses (other than handling fees) 

increased $841,408 in 2012 compared to 2011.

Expenditures for G&A, interest and other expenses during 2012 increased 

$343,927, as compared to the 2011. These expenditures were the result of higher 

 personnel, technical consulting, auditing, tax preparation and legal costs.

Net cash provided (used) by:

 2012 2011 Change

Operating activities $ 25,371,195 $ 29,283,929 $ (3,912,734)

Investing activities $ (38,288,959) $ (27,200,816) $ (11,088,143)

Financing activities $ 11,394,864 $ (4,173,372) $ 15,568,236

Increase (decrease) in cash and cash equivalents $ (1,522,900) $ (2,090,259) $ 567,359
(33)

Investing activities:

Net cash used in investing activities increased $11,088,143 during the 2012 period, the 

result of the following:

Capital expenditures for drilling activity increased $2,407,398 from $22,739,908 in 

2011 to $25,147,306 in 2012.

 The Company acquired producing properties, leasehold and mineral acreage in 

Arkansas and Oklahoma totaling $20,144,121 during 2012, as compared to 

$4,805,440 during 2011, a $15,338,681 increase.

Lease bonus payments received increased $6,876,001 during 2012, as compared to 

 2011. 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 provided by financing activities in 2012 was $11,394,864, as compared to 2011 

net cash used in financing activities of $4,173,372. The net cash provided increase of 

$15,568,236 is explained as follows:

The Company financed the acquisitions of producing properties, mineral acreage 

and leasehold in Arkansas and Oklahoma utilizing its credit facility with Bank of 

 Oklahoma and cash. These acquisitions and higher expenditures to drill and 

complete wells in 2012, as compared to 2011, resulted in cash provided by 

financing activities through net borrowings during 2012 of $14,874,985, as 

compared to $0 in 2011.

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

Capital expenditures for drilling increased approximately $2.4 million (11%) from 2011 to 2012 

as drilling activity, primarily in the Fayetteville Shale, western Oklahoma and the Texas Panhandle 

continued at a relatively steady pace during the first three quarters of 2012 and then increased 

significantly during the 2012 fourth quarter and thus far into 2013. A significant portion of the 

Fayetteville Shale drilling continued to be on the acreage acquired during the 2012 first quarter. In 

western Oklahoma, the Texas Panhandle and other areas drilling continues to be very active where the 

Company owns substantial mineral and leasehold acreage in oil and liquids-rich areas, which include the 

following horizontal and vertical plays:

• Horizontal Granite Wash 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

• Vertical Mississippian in northern Oklahoma
(34)

• Vertical Spraberry in West Texas

• Vertical Yeso in southeastern New Mexico

• Horizontal Anadarko Basin Woodford Shale in western Oklahoma

• Horizontal Ardmore Basin Woodford Shale in southern Oklahoma

Capital expenditures for drilling projects in 2012 were $25,147,306, while 2012 asset 

acquisitions totaled $20,144,121, a combined $45,291,427. Capital expenditures for drilling projects in 

2013 are expected to be approximately $25 million. Although there may be decreases in oil, NGL and 

natural gas 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 for 2013. We 

will also continue to evaluate opportunities to acquire additional production or acreage.

Please note, 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, NGL or natural gas 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 is well-by-well or on a broader scope, to determine the optimum method to maximize the 

value of Panhandle’s assets.

Production of oil, NGL and natural gas increased 19% 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 two years 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. Prior to then, the quarterly reports and 

reserve calculations included NGL sales revenues with natural gas sales revenues. Production increased 

in 2012 as a result of the addition of acquired wells and new wells production exceeding the natural 

production decline of existing wells. Looking forward, we expect 2013 production to exceed 2012 

production as wells continue to come on line throughout fiscal 2013.

Natural gas prices received by the Company declined through May 2012 to below $2.00 per 

Mmbtu, but rebounded to approximately $2.40 per Mmbtu during September 2012. NYMEX natural gas 

futures prices (the Company receives on average approximately 93% of NYMEX price for its natural gas 

sales) indicate price improvement to the mid $3.00 per Mmbtu level as an average for fiscal 2013. As of 

September 30, 2012, the Company had costless collar contracts covering 7,000 barrels per month of oil 

production through December 2012, 430,000 Mmbtu per month of natural gas production through 

October 2012, 350,000 Mmbtu per month of natural gas production from November 2012 through 

January 2013, and basis protection swap contracts covering 190,000 Mmbtu per month of natural gas 

production through December 2012. With continued oil and natural gas price volatility, management
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continues to evaluate opportunities for product price protection by hedging a portion of the Company’s 

future oil and natural gas production.

Cash provided by operating activities during 2012 of $25,371,196 funded capital expenditures for 

drilling and equipping wells of $25,147,306. After payment of our regular $.07 per share quarterly 

dividends totaling $2,321,164, treasury stock purchases of $1,158,957, net borrowings under the 

Company’s revolving credit facility of $14,874,985 and other miscellaneous investing activities, cash 

was reduced during 2012 by $1,522,900. During 2012, the Company utilized excess cash and the bank 

credit facility to finance approximately $20 million in asset purchases. Net outstanding borrowings on the 

credit facility at September 30, 2012, were $14,874,985. 

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, NGL and 

natural gas 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 ($20,125,015 at 

September 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 2013, the Company 

has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit 

facility, to fund additional acquisitions.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving 

loan with a limit in the amount of $80,000,000 which is subject to a semi-annual borrowing base 

determination. The current borrowing base is $35,000,000 and is secured by certain of the Company’s 

properties with a carrying value of $41,343,303 at September 30, 2012. The revolving loan matures on 

November 30, 2014. Borrowings under the revolving loan are due at maturity. The revolving loan bears 

interest at the national prime rate plus a range of .50% to 1.25%, or 30 day LIBOR plus a range of 2.00% 

to 2.75% annually. 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.

Determinations of the borrowing base are made semi-annually or whenever BOK believes there 

has been a material change in the value of the Company’s oil and natural gas properties. 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 September 30, 2012, 

the Company was in compliance with these covenants.

The table below summarizes the Company’s contractual obligations and commitments as of 

September 30, 2012:
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At September 30, 2012, the Company’s derivative contracts were in a liability position of 

$172,271. The ultimate settlement amounts of the derivative contracts are unknown because they are 

subject to continuing market risk. Please read Item 7A – “Quantitative and Qualitative Disclosures about 

Market Risk” and Note 1 to the financial statements included in Item 8 – “Financial Statements and 

Supplementary Data” for additional information regarding the derivative contracts.

As of September 30, 2012, the Company’s asset retirement obligations were $2,122,950. Asset 

retirement obligations represent the Company’s share of the future expenditures to plug and abandon the 

wells in which the Company owns a working interest when the oil, NGL and natural gas reserves are 

depleted. These amounts were not included in the schedule above due to the uncertainty of timing of the 

obligations. Please read Note 1 to the financial statements included in Item 8 – “Financial Statements and 

Supplementary Data” for additional information regarding the Company’s asset retirement obligations.

CRITICAL ACCOUNTING POLICIES

Preparation of financial statements in conformity with accounting principles generally accepted in 

the United States requires management to make estimates, judgments and assumptions that affect the 

reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and 

liabilities. However, the accounting principles used by the Company generally do not change the 

Company’s reported cash flows or liquidity. Existing rules must be interpreted and judgments made on 

how the specifics of a given rule apply to the Company.

The more significant reporting areas impacted by management’s judgments and estimates are 

crude oil, NGL and natural gas reserve estimation, derivative contracts, impairment of assets, oil, NGL 

and natural gas sales revenue accruals, refundable production taxes and provision for income tax. 

Management’s judgments and estimates in these areas are based on information available from both 

internal and external sources, including engineers, geologists, consultants and historical experience in 

similar matters. Actual results could differ from the estimates as additional information becomes known. 

The oil, NGL and natural gas sales revenue accrual is particularly subject to estimate inaccuracies due to 

the Company’s status as a non-operator on all of its properties. As such, production and price information 

obtained from well operators is substantially delayed. This causes the estimation of recent production and 

prices used in the oil, NGL and natural gas revenue accrual to be subject to future change.

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. These estimates affect the unaudited 

standardized measure disclosures included in Note 11 to the financial statements in Item 8 – “Financial 

Statements and Supplementary Data,” as well as DD&A and impairment calculations. Changes in crude 

oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, asset retirement 

obligations 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 geologic and 

seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance

 Payments due by period

Contractual Obligations Less than More than

and Commitments Total 1 Year 1-3 Years 3-5 Years 5 Years

Long-term debt obligations $ 14,874,985 $ - $ 14,874,985 $ - $ -

Building lease $ 527,229 $ 204,089 $ 323,140 $ - $ -
(37)

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 prices which are updated through the current period. In accordance with the 

SEC rules, the reserve estimates were based on average individual product prices during the 12-month 

period prior to September 30 determined as an unweighted arithmetic average of the first-day-of-themonth price for each month within such period, unless prices were defined by contractual arrangements, 

excluding escalations based upon future conditions. Based on the Company’s 2012 DD&A, a 10% 

change in the DD&A rate per Mcfe would result in a corresponding $1,906,124 annual change in DD&A 

expense. Crude oil, NGL and natural gas prices are volatile and largely affected by worldwide production 

and consumption and are outside the control of management. 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. 

Successful Efforts Method of Accounting

The Company has elected to utilize the successful efforts method of accounting for its oil and 

natural gas exploration and development activities. This means exploration expenses, including 

geological and geophysical costs, non producing lease impairment, rentals and exploratory dry holes, are 

charged against income as incurred. Costs of successful wells and related production equipment and 

developmental dry holes are capitalized and amortized by property using the unit-of-production method 

(the ratio of oil, NGL and natural gas volumes produced to total proved or proved developed reserves is 

used to amortize the remaining asset basis on each producing property) as oil, NGL and natural gas is 

produced. The Company’s exploratory wells are all on-shore and primarily located in the Mid-Continent 

area. Generally, expenditures on exploratory wells comprise less than 10% of the Company’s total 

expenditures for oil and natural gas properties. This accounting method may yield significantly different 

operating results than the full cost method.

Derivative Contracts

The Company entered into oil costless collar contracts, natural gas costless collar contracts, 

natural gas fixed swap contracts and natural gas basis protection swaps. These instruments are intended 

to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Collar 

contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the 

index price falls below the floor or require payments by the Company if the index price rises above the 

ceiling. Fixed swap contracts set a fixed price and provide for 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 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. These contracts cover 

only a portion of the Company’s oil and natural gas production and provide only partial price protection 

against declines in oil and natural gas 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 unsecured.

The Company is required to recognize all derivative instruments as either assets or liabilities in 

the balance sheet at fair value. The accounting for changes in the fair value of a derivative depends on the 

intended use of the derivative and resulting designation. At September 30, 2012, the Company had no 

derivative contracts designated as cash flow hedges, and therefore, changes in the fair value of 

derivatives are reflected in earnings.
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Impairment of Assets

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 Company estimates future net cash 

flows on its oil and natural gas properties utilizing differentially adjusted forward pricing curves for oil, 

NGL and natural gas and a discount rate in line with the discount rate we believe is most commonly used 

by the market participants (10% for all periods presented). 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. A significant reduction in oil, NGL and natural gas prices (which are reviewed quarterly) or 

a decline in reserve volumes (which are re-evaluated semi-annually) would likely lead to additional 

impairment that may be material to the Company. Any assets held for sale are reviewed for impairment 

when the Company approves the plan to sell. Estimates of anticipated sales prices are highly judgmental 

and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the 

Company cannot predict when or if future impairment charges will be recorded. 

Non-producing oil and natural gas leases are assessed for impairment on a property-by-property 

basis for individually significant balances and on an aggregate basis for individually insignificant 

balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation 

allowance at the level at which impairment was assessed. The impairment assessment is affected by 

economic factors such as the results of exploration activities, commodity price outlooks, remaining lease 

terms and potential shifts in business strategy employed by management. In the case of individually 

insignificant balances, the amount of the impairment loss recognized is determined by amortizing the 

portion of these properties’ costs, which the Company believes will not be transferred to proved 

properties over the remaining lives of the leases. Impairment loss is charged to exploration costs when 

recognized. As of September 30, 2012, the remaining carrying cost of non-producing oil and natural gas 

leases was $694,968.

Oil, NGL and Natural Gas Sales Revenue Accrual

The Company does not operate its oil and natural gas properties and, therefore, receives actual oil, 

NGL and natural gas sales volumes and prices (in the normal course of business) over a month later than 

the information is available to the operators of the wells. This being the case, on wells with greater 

significance to the Company, the most current available production data is gathered from the appropriate 

operators, and oil, NGL and natural gas index prices local to each well are used to estimate the accrual of 

revenue on these wells. Timely obtaining production data on all other wells from the operators is not 

feasible; therefore, the Company utilizes past production receipts and estimated sales price information to 

estimate its accrual of revenue on all other wells each quarter. The oil, NGL and natural gas sales revenue 

accrual can be impacted by many variables including rapid production decline rates, production 

curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market 

prices for oil, NGL and natural gas. These variables could lead to an over or under accrual of oil, NGL 

and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated 

accrual has been materially accurate.

Income Taxes

The estimation of the amounts of income tax to be recorded by the Company involves 

interpretation of complex tax laws and regulations, as well as the completion of complex calculations, 

including the determination of the Company’s percentage depletion deduction, if any. To calculate the
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exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at 

the end of each fiscal year. During interim periods, an estimate is made taking into account historical data 

and current pricing. The Company has certain state net operating loss carry forwards (NOLs) that are 

recognized as tax assets when assessed as more likely than not to be utilized before their expiration dates. 

Criteria such as expiration dates, future excess state depletion and reversing taxable temporary 

differences are evaluated to determine whether the NOLs are more likely than not to be utilized before 

they expire. If any NOLs are determined to no longer be more likely than not to be utilized, then a 

valuation allowance is recognized to reduce the tax benefit of such NOLs. Although the Company’s 

management believes its tax accruals are adequate, differences may occur in the future depending on the 

resolution of pending and new tax matters.

Refundable Production Taxes Accrual

The State of Oklahoma allows for refunds of production taxes on wells that are horizontally 

drilled. In order to qualify as a horizontally drilled well, the well must have been completed in a manner 

which encounters and subsequently produces from a geological formation at an angle in excess of 

seventy degrees from the vertical and which laterally penetrates a minimum of one hundred and fifty feet 

into the pay zone of the formation. An operator has 18 months after a given tax year to file the 

appropriate forms with the Oklahoma Tax Commission requesting the refund of production taxes. The 

refund is limited to 48 months from first sales or well payout, whichever comes first. Horizontal drilling 

in Oklahoma over the past four years has resulted in the addition of numerous wells that qualify for the 

Oklahoma horizontal exemption, thus increasing the Company’s oil, NGL and natural gas sales subject to 

the accrual.

The Company does not operate any of its oil and natural gas properties and thus must rely on oil, 

NGL and natural gas sales and drilling information from the operators. The Company utilizes payment 

remittances from operators to estimate its refundable production tax accrual at the end of each quarterly 

period. The refundable production tax accrual can be impacted by many variables, including subsequent 

revenue adjustments received from operators and an operator’s failure to file timely with the Oklahoma 

Tax Commission requesting refunds. These variables could lead to an over or under accrual of production 

taxes at the end of any particular period. Based on historical experience, the estimated accrual has been 

materially accurate.

During the 2010 legislative session, the Oklahoma State Legislature passed House Bill 2432, 

which provided for the deferral of the payment of certain gross production tax rebates by the Oklahoma 

Tax Commission for the production periods ending June 30, 2010, (tax year 2010) and June 30, 2011, 

(tax year 2011) for horizontally drilled wells. These deferred payments are being paid out over a period 

of three years beginning July 1, 2012. As a concession to producers for accepting the three-year deferral 

period, the State of Oklahoma, beginning with July 1, 2012, production, reduced the production tax rate 

rather than pay rebates in future periods. As such, the latest production date in the refundable production 

tax accrual is June 30, 2011. Given that the Company has received essentially all revenues for Oklahoma 

horizontal wells for the production periods through June 30, 2011, the refundable production tax accrual 

should not increase in amount in future periods and should decrease consistently over the next three fiscal 

years until completely refunded. 

The above description of the Company’s critical accounting policies is not intended to be an allinclusive discussion of the uncertainties considered and estimates made by management in applying 

generally accepted accounting principles and policies. Results may vary significantly if different policies 

were used or required and if new or different information becomes known to management.
(40)

ITEM 7A 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 wide divergence in the opinions held 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 natural gas derivative contracts (see below), 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 $1,050,000 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 is approximately 

$155,000 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 September 30, 2012, the Company has natural gas 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 natural gas 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 

$57,000. 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 $58,000. 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 $10,000.

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 facility. 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 September 30, 2012, the 

Company had $14,874,985 outstanding under this facility. 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.
(41)

ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Annual Report on Internal Control Over Financial Reporting................. 42

Report of Registered Public Accounting Firm on Internal Control

Over Financial Reporting.......................................................................... 43

Report of Independent Registered Public Accounting Firm.................................. 44

Balance Sheets

As of September 30, 2012 and 2011.............................................................. 45

Statements of Operations for the 

Years Ended September 30, 2012, 2011 and 2010............................................. 47

Statements of Stockholders’ Equity for the

Years Ended September 30, 2012, 2011 and 2010............................................. 48

Statements of Cash Flows for the

Years Ended September 30, 2012, 2011 and 2010............................................. 49

Notes to Financial Statements..................................................................... 51
(42)

Management’s Annual Report on Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal 

control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 

15d-15(f) under the Securities Exchange Act of 1934 (the “Exchange Act”) as a process designed by, or 

under the supervision of, the Company’s principal executive and principal financial officers and effected 

by the Company’s board of directors, management and other personnel, to provide reasonable assurance 

regarding the reliability of financial reporting and the preparation of financial statements for external 

purposes in accordance with generally accepted accounting principles, and includes those policies and 

procedures that:

• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect 

 the transactions and dispositions of the assets of the Company;

• Provide reasonable assurance that transactions are recorded as necessary to permit 

preparation of financial statements in accordance with generally accepted accounting 

 principles, and that receipts and expenditures of the Company are being made only in 

accordance with authorizations of management and directors of the Company; and

• Provide reasonable assurance regarding prevention or timely detection of unauthorized 

 acquisition, use or disposition of the Company’s assets that could have a material effect on 

the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or 

detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to 

the risk that controls may become inadequate because of changes in conditions, or that the degree of 

compliance with the policies or procedures may deteriorate. Internal control over financial reporting 

cannot provide absolute assurance of achieving financial reporting objectives because of its inherent 

limitations. Internal control over financial reporting is a process that involves human diligence and 

compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal 

control over financial reporting also can be circumvented by collusion or improper management override. 

Because of such limitations, there is a risk that material misstatements may not be prevented or detected 

on a timely basis by internal control over financial reporting. However, these inherent limitations are 

known features of the financial reporting process. Therefore, it is possible to design into the process 

safeguards to reduce, though not eliminate, this risk.

The Company’s management assessed the effectiveness of the Company’s internal control over 

financial reporting as of September 30, 2012. In making this assessment, the Company’s management 

used the criteria set forth in Internal Control – Integrated Framework issued by the Committee of 

Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, management 

has concluded that, as of September 30, 2012, the Company’s internal control over financial reporting 

was effective based on those criteria.

Our independent registered public accounting firm has issued an attestation report on our internal 

control over financial reporting. This report appears on the following page.
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Report of Independent Registered Public Accounting Firm 

on Internal Control Over Financial Reporting 

The Board of Directors and Stockholders of 

Panhandle Oil and Gas Inc. 

We have audited Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2012, based on 

criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of 

the Treadway Commission (the COSO criteria). Panhandle Oil and Gas Inc.’s management is responsible for maintaining 

effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial 

reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our 

responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal 

control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of 

internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design 

and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we 

considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the 

reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally 

accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures 

that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and 

dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to 

permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and 

expenditures of the company are being made only in accordance with authorizations of management and directors of the 

company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or 

disposition of the company’s assets that could have a material effect on the financial statements. 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, 

projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate 

because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 

In our opinion, Panhandle Oil and Gas Inc. maintained, in all material respects, effective internal control over financial 

reporting as of September 30, 2012, based on the COSO criteria. 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), 

the balance sheets of Panhandle Oil and Gas Inc. as of September 30, 2012 and 2011, and the related statements of operations, 

stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2012 and our report dated 

December 11, 2012 expressed an unqualified opinion thereon. 

 

 /s/ Ernst & Young LLP 

Oklahoma City, Oklahoma 

December 11, 2012
(44)

 Report of Independent Registered Public Accounting Firm 

The Board of Directors and Stockholders of

Panhandle Oil and Gas Inc. 

We have audited the accompanying balance sheets of Panhandle Oil and Gas Inc. (the Company) as of September 30, 2012 

and 2011, and the related statements of operations, stockholders’ equity, and cash flows for each of the three years in the 

period ended September 30, 2012. These financial statements are the responsibility of the Company’s management. Our 

responsibility is to express an opinion on these financial statements based on our audits. 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United 

States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial 

statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts 

and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant 

estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits 

provide a reasonable basis for our opinion. 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of 

Panhandle Oil and Gas Inc. at September 30, 2012 and 2011, and the results of its operations and its cash flows for each of the 

three years in the period ended September 30, 2012, in conformity with U.S. generally accepted accounting principles. 

As discussed in Note 1 to the financial statements, in 2010 Panhandle Oil and Gas Inc. changed its reserve estimates and 

related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),

Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2012, based on criteria established 

in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway 

Commission and our report dated December 11, 2012, expressed an unqualified opinion thereon. 

/s/ Ernst & Young LLP 

Oklahoma City, Oklahoma

December 11, 2012
(45)

September 30,

2012 2011 

Assets

Current Assets:

Cash and cash equivalents $ 1,984,099 $ 3,506,999

Oil, NGL and natural gas sales receivables 8,349,865 8,811,404

Refundable income taxes 325,715 354,246

Refundable production taxes 585,454 223,672

Deferred income taxes 121,900 -

Derivative contracts - 269,329

Other 255,812 95,408

Total current assets 11,622,845 13,261,058

Properties and equipment at cost, based on successful

efforts accounting:

Producing oil and natural gas properties 275,997,569 230,554,198

Non-producing oil and natural gas properties 10,150,561 11,100,350

Furniture and fixtures 668,004 628,929

286,816,134 242,283,477

 Less accumulated depreciation, depletion and

amortization 165,199,079 146,147,514

Net properties and equipment 121,617,055 96,135,963

Investments 1,034,870 667,504

Refundable production taxes 911,960 1,359,668

Total assets $ 135,186,730 $ 111,424,193

Panhandle Oil and Gas Inc.

Balance Sheets

(Continued on next page)

See accompanying notes.
(46)

September 30,

2012 2011

Liabilities and Stockholders’ Equity

Current Liabilities:

Accounts payable $ 6,447,692 $ 4,899,593

Derivative contracts 172,271 -

Deferred income taxes - 7,100

Accrued liabilities and other 1,007,779 1,040,269

Total current liabilities 7,627,742 5,946,962

Long term debt 14,874,985 -

Deferred income taxes 26,708,907 24,777,650

Asset retirement obligations 2,122,950 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

 September 30,2012 and 2011 140,524 140,524

Capital in excess of par value 2,020,229 1,924,507

Deferred directors’ compensation 2,676,160 2,665,583

Retained earnings 84,821,395 79,771,563

89,658,308 84,502,177

Treasury stock, at cost; 181,310 shares at

 September 30, 2012, and 175,331 shares at

September 30, 2011 (5,806,162) (5,699,860)

Total stockholders’ equity 83,852,146 78,802,317

Total liabilities and stockholders’ equity $ 135,186,730 $ 111,424,193

Panhandle Oil and Gas Inc.

Balance Sheets

See accompanying notes.
(47)

Year ended September 30,

2012 2011 2010

Revenues:

Oil, NGL and natural gas sales $ 40,818,434 $ 43,469,130 $ 44,068,947

Lease bonuses and rentals 7,152,991 352,757 1,120,674

Gains (losses) on derivative contracts 73,822 734,299 6,343,661

Income from partnerships 487,070 420,465 405,134

48,532,317 44,976,651 51,938,416

Costs and expenses:

Lease operating expenses 9,141,970 8,441,754 8,193,319

Production taxes 1,449,537 1,456,755 1,446,545

Exploration costs 979,718 1,025,542 1,583,773

Depreciation, depletion and amortization 19,061,239 14,712,188 19,222,123

Provision for impairment 826,508 1,728,162 605,615

Loss (gain) on asset sales, interest and other 39,493 (68,325) (1,028,148)

General and administrative 6,388,856 5,994,663 5,594,499

37,887,321 33,290,739 35,617,726

Income (loss) before provision (benefit)

for income taxes 10,644,996 11,685,912 16,320,690

Provision (benefit) for income taxes 3,274,000 3,192,000 4,901,000

Net income (loss) $ 7,370,996 $ 8,493,912 $ 11,419,690

Basic and diluted earnings per common share:

Net income (loss) $ 0.88 $ 1.01 $ 1.36

Panhandle Oil and Gas Inc.

Statements of Operations

See accompanying notes.
(48)

 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, 2009 8,431,502 $ 140,524 $ 1,922,053 $ 1,862,499 $ 64,507,547 (119,866) $ (4,310,280) $ 64,122,343

Purchase of treasury stock - - - - - (12,326) (291,383) (291,383)

Issuance of treasury shares to ESOP - - (117,716) - - 11,632 404,910 287,194

Restricted stock awards - - 12,028 - - - - 12,028

Common shares to be issued to

directors for services - - - 359,628 - - - 359,628

Dividends declared ($.28 per share) - - - - (2,327,504) - - (2,327,504)

Net income - - - - 11,419,690 - - 11,419,690

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)

Issuance of treasury shares to ESOP - - (44,340) - - 10,710 348,183 303,843

Restricted stock awards - - 152,482 - - - - 152,482

Common shares to be issued to

directors for services - - - 443,456 - - - 443,456

Dividends declared ($.28 per share) - - - - (2,322,082) - - (2,322,082)

Net income - - - - 8,493,912 - - 8,493,912

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)

Issuance of treasury shares to ESOP - - (14,391) - - 10,660 341,333 326,942

Restricted stock awards - - 330,923 - - - - 330,923

Distribution of deferred directors’

compensation - - (220,810) (406,770) - 22,132 711,322 83,742

Common shares to be issued to

directors for services - - - 417,347 - - - 417,347

Dividends declared ($.28 per share) - - - - (2,321,164) - - (2,321,164)

Net income - - - - 7,370,996 - - 7,370,996

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

Panhandle Oil and Gas Inc.

Statements of Stockholders’ Equity

See accompanying notes.
(49)

Year ended September 30,

2012 2011 2010

Operating Activities

Net income (loss) $ 7,370,996 $ 8,493,912 $ 11,419,690

Adjustments to reconcile net income (loss) to net

cash provided by operating activities:

Depreciation, depletion and amortization 19,061,239 14,712,188 19,222,123

Impairment 826,508 1,728,162 605,615

Provision for deferred income taxes 1,802,257 1,878,000 777,000

Exploration costs 979,718 1,025,542 1,208,653

Gain from leasing of fee mineral acreage (7,146,299) (352,642) (1,189,648)

Net (gain) loss on sales of assets (122,504) 2,112 43

Income from partnerships (487,070) (420,465) (405,134)

Distributions received from partnerships 601,300 553,382 523,317

Other - - 64,555

Common stock contributed to ESOP 326,942 303,843 287,194

Common stock (unissued) to Directors’

Deferred Compensation Plan 417,347 443,456 359,628

Restricted stock awards 330,923 152,482 12,028

Cash provided (used) by changes in assets

 and liabilities:

Oil, NGL and natural gas sales receivables 461,539 251,598 (1,315,445)

Fair value of derivative contracts 388,211 1,404,386 (4,133,761)

Refundable income taxes 28,531 (354,246) -

Refundable production taxes 85,926 (124,621) (69,874)

Other current assets (108,098) 317,370 (343,961)

Accounts payable 585,912 72,119 (24,896)

Other non-current assets 308 - -

Income taxes payable - (922,136) 583,625

Accrued liabilities (32,490) 119,487 225,723

Total adjustments 18,000,200 20,790,017 16,386,785

Net cash provided by operating activities 25,371,196 29,283,929 27,806,475

(Continued on next page)

Panhandle Oil and Gas Inc.

Statements of Cash Flows
(50)

Panhandle Oil and Gas Inc.

Statements of Cash Flows (continued)

See accompanying notes.

Year ended September 30,

2012 2011 2010

Investing Activities

Capital expenditures, including dry hole costs $ (25,147,306) $(22,739,908) $(11,308,506)

Acquisition of working interest properties (17,399,052) (185,125) -

Acquisition of minerals and overrides (2,745,069) (4,620,315) -

Proceeds from leasing of fee mineral acreage 7,265,808 389,807 1,316,377

Investments in partnerships (481,904) (46,213) (254,555)

Proceeds from sales of assets 134,821 938 401,168

Excess tax benefit on stock-based compensation 83,742 - -

Net cash used in investing activities (38,288,960) (27,200,816) (9,845,516)

Financing Activities

Borrowings under debt agreement 43,475,443 - 10,799,814

Payments of loan principal (28,600,458) - (21,184,536)

Purchases of treasury stock (1,158,957) (1,851,290) (291,383)

Payments of dividends (2,321,164) (2,322,082) (2,327,504)

Net cash provided by (used in) financing activities 11,394,864 (4,173,372) (13,003,609)

Increase (decrease) in cash and cash equivalents (1,522,900) (2,090,259) 4,957,350

Cash and cash equivalents at beginning of year 3,506,999 5,597,258 639,908

Cash and cash equivalents at end of year $ 1,984,099 $ 3,506,999 $ 5,597,258

Supplemental Disclosures of Cash Flow

Information

Interest paid (net of capitalized interest) $ 127,970 $ - $ 60,912

Income taxes paid, net of refunds received $ 1,356,706 $ 2,584,172 $ 3,530,718

Supplemental schedule of noncash

investing and financing activities:

Additions and revisions, net, to asset

retirement obligations $ 279,075 $ 113,506 $ 110,144

Gross additions to properties and equipment $ 46,201,308 $ 27,310,016 $ 11,585,521

Net (increase) decrease in accounts payable for

properties and equipment additions (909,881) 235,332 (277,015)

Capital expenditures, including dry hole costs $ 45,291,427 $ 27,545,348 $ 11,308,506
(51)

Panhandle Oil and Gas Inc.

Notes to Financial Statements

September 30, 2012, 2011 and 2010

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Since its formation, the Company has been involved in the acquisition and management of fee 

mineral acreage and the exploration for, and development of, oil and natural gas properties, principally 

involving drilling wells located on the Company’s mineral acreage. Panhandle’s mineral properties and 

other oil and natural gas interests are all located in the United States, primarily in Arkansas, New 

Mexico, North Dakota, Oklahoma and Texas. The Company is not the operator of any wells. The 

Company’s oil, NGL and natural gas production is from interests in 5,666 wells located principally in 

Oklahoma and Arkansas. Approximately 58% of oil, NGL and natural gas revenues were derived from 

the sale of natural gas in 2012. Approximately 86% of the Company’s total sales volumes in 2012 were 

derived from the sale of natural gas. Substantially all the Company’s oil, NGL and natural gas production 

is sold through the operators of the wells. The Company from time to time disposes of certain nonmaterial, non-core or small-interest oil and natural gas properties in the normal course of business.

Basis of Presentation

Certain amounts (lease operating expenses and production taxes in the Statements of Operations; 

capital expenditures and net (gain) loss on sales of assets in the Statements of Cash Flows) in the prior 

years have been reclassified to conform to the current year presentation.

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in 

the United States requires management to make estimates and assumptions that affect the amounts and 

disclosures reported in the financial statements and accompanying notes. Actual results could differ from 

those estimates.

Of these estimates and assumptions, management considers the estimation of crude oil, NGL and 

natural gas reserves to be the most significant. These estimates affect the unaudited standardized measure 

disclosures, as well as DD&A and impairment calculations. On an annual basis, with a semi-annual 

update, the Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, 

prepares estimates of crude oil, NGL and natural gas reserves based on available geologic 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. For 

DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve 

estimates were based on average individual product prices during the 12-month period prior to September 

30 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month 

within such period, unless prices were defined by contractual arrangements, excluding escalations based 

upon future conditions. For impairment purposes, projected future crude oil, NGL and natural gas prices 

as estimated by management are used. Crude oil, NGL and natural gas prices are volatile and largely 

affected by worldwide production and consumption and are outside the control of management. 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 used in formulating management’s overall operating 

decisions.
(52)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The Company does not operate its oil and natural gas properties and, therefore, receives actual oil, 

NGL and natural gas sales volumes and prices (in the normal course of business) over a month later than 

the information is available to the operators of the wells. This being the case, on wells with greater 

significance to the Company, the most current available production data is gathered from the appropriate 

operators, and oil, NGL and natural gas index prices local to each well are used to estimate the accrual of 

revenue on these wells. Timely obtaining production data on all other wells from the operators is not 

feasible; therefore, the Company utilizes past production receipts and estimated sales price information to 

estimate its accrual of revenue on all other wells each quarter. The oil, NGL and natural gas sales revenue 

accrual can be impacted by many variables including rapid production decline rates, production 

curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market 

prices for oil, NGL and natural gas. These variables could lead to an over or under accrual of oil, NGL 

and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated 

accrual has been materially accurate.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds invested in short-term 

investments with original maturities of three months or less.

Oil, NGL and Natural Gas Sales and Natural Gas Imbalances

The Company sells oil, NGL and natural gas to various customers, recognizing revenues as oil, 

NGL and natural gas is produced and sold. Charges for compression, marketing, gathering and 

transportation of natural gas are included in lease operating expenses.

The Company uses the sales method of accounting for natural gas imbalances in those 

circumstances where it has underproduced or overproduced its ownership percentage in a property. 

Under this method, a receivable or liability is recorded to the extent that an underproduced or 

overproduced position in a well cannot be recouped through the production of remaining reserves. At 

September 30, 2012 and 2011, the Company had no material natural gas imbalances.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Company’s accounts receivable are due from purchasers of oil, NGL and 

natural gas or operators of the oil and natural gas properties. Oil, NGL and natural gas sales receivables 

are generally unsecured. This industry concentration has the potential to impact our overall exposure to 

credit risk, in that the purchasers of our oil, NGL and natural gas and the operators of the properties we 

have an interest in may be similarly affected by changes in economic, industry or other conditions. 

During 2012 and 2011, we did not recognize a reserve for bad debt expense.

Derivative contracts entered into by the Company are also unsecured.

Oil and Natural Gas Producing Activities

The Company follows the successful efforts method of accounting for oil and natural gas 

producing activities. Intangible drilling and other costs of successful wells and development dry holes are

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)
(53)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against 

income if and when the well is determined to be nonproductive. Oil and natural gas mineral and 

leasehold costs are capitalized when incurred.

Non-producing oil and natural gas leases are assessed for impairment on a property-by-property 

basis for individually significant balances and on an aggregate basis for individually insignificant 

balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation 

allowance at the level at which impairment was assessed. The impairment assessment is affected by 

economic factors such as the results of exploration activities, commodity price outlooks, remaining lease 

terms and potential shifts in business strategy employed by management. In the case of individually 

insignificant balances, the amount of the impairment loss recognized is determined by amortizing the 

portion of these properties’ costs, which the Company believes will not be transferred to proved 

properties over the remaining lives of the leases. Impairment loss is charged to exploration costs when 

recognized. As of September 30, 2012, the remaining carrying cost of non-producing oil and natural gas 

leases was $694,968.

It is common business practice in the petroleum industry for drilling costs to be prepaid before 

spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, 

but at times will utilize letters of credit to meet these obligations. As of September 30, 2012, the 

Company had no outstanding letters of credit. 

Lease Bonus

When the Company leases its mineral acreage to third-party exploration and production 

companies, it retains a royalty interest in any future revenues from the production and sale of oil, NGL or 

natural gas, and often times receives an up-front, non-refundable, cash payment (lease bonus payment) in 

addition to the retained royalty interest. A royalty interest does not bear any portion of the cost of 

drilling, completing or operating a well; these costs are borne by the working interest owner. The 

Company sometimes leases only a portion of its mineral acres in a tract and retains the right to participate 

as a working interest owner with the remainder.

The Company recognizes revenue from mineral lease bonus payments when it has received an 

executed agreement with the exploration company transferring the rights to explore for and produce any 

oil or natural gas it may find within the term of the lease, the payment has been collected, and the 

Company has no obligation to refund the payment. The Company accounts for its lease bonuses in 

accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery 

with any excess above the mineral basis being treated as a gain. The excess of lease bonus above the 

mineral basis is shown in the lease bonuses and rentals line item on the Company’s Statements of 

Operations.

Derivatives

The Company entered into oil costless collar contracts, natural gas costless collar contracts, 

natural gas fixed swap contracts and natural gas basis protection swaps. These instruments were intended 

to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Collar 

contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)
(54)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

index price falls below the floor or require payments by the Company if the index price rises above the 

ceiling. 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 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. These contracts cover 

only a portion of the Company’s oil and natural gas production and provide only partial price protection 

against declines in oil and natural gas 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 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.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)
(55)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Derivative contracts in place as of September 30, 2011

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

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

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

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

Production volume Indexed (1)

Contract period covered per month 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
(56)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Derivative contracts in place as of September 30, 2012

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

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 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 liability of $172,271 as of 

September 30, 2012, and a net asset of $215,940 as of September 30, 2011. Realized and unrealized gains 

and (losses) are scheduled below:

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

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

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

Production volume Indexed (1)

Contract period covered per month 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
(57)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 September 30, 2012, and September 30, 2011:

(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 only if the 

impact is deemed material. The impact of credit risk was immaterial for all periods presented.

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

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Balance Sheet 9/30/2012 9/30/2011

Location Fair Value Fair Value

Asset Derivatives:

Derivatives not designated as Hedging Instruments:

Commodity contracts Short-term derivative contracts $ - $ 269,329

Commodity contracts Long-term derivative contracts - -

 Total Asset Derivatives (a) $ - $ 269,329

Liability Derivatives:

Derivatives not designated as Hedging Instruments:

Commodity contracts Short-term derivative contracts $ 172,271 $ -

Commodity contracts Long-term derivative contracts - 53,389

 Total Liability Derivatives (a) $ 172,271 $ 53,389

Gains (losses) on natural gas Fiscal year ended 

 derivative contracts 9/30/2012 9/30/2011 9/30/2010

Realized $ 462,033 $ 2,138,685 $ 2,209,900

Increase (decrease) in fair value (388,211) (1,404,386) 4,133,761

Total $ 73,822 $ 734,299 $ 6,343,661
(58)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

corroborated by, observable market data by correlation or other means. Level 3 inputs are unobservable 

inputs for the financial asset or liability. Counterparty quotes are generally assessed as a Level 3 input.

The following table provides fair value measurement information for financial assets and 

liabilities measured at fair value on a recurring basis.

 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 

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

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, future prices, 

volatility and time to maturity. These values are then compared to the values given by our 

counterparties for reasonableness.

 Fair Value Measurement at September 30, 2012

Quoted Significant

Prices in Other Significant

Active Observable Unobservable

Markets Inputs Inputs Total Fair

(Level 1) (Level 2) (Level 3) Value

Financial Assets (Liabilities):

Derivative Contracts - Swaps $ - $ (75,334) $ - $ (75,334)

Derivative Contracts - Collars $ - $ - $ (96,937) $ (96,937)

 Fair Value Measurement at September 30, 2011

Quoted Significant

Prices in Other Significant

Active Observable Unobservable

Markets Inputs Inputs Total Fair

(Level 1) (Level 2) (Level 3) Value

Financial Assets (Liabilities):

Derivative Contracts - Swaps $ - $ (77,907) $ - $ (77,907)

Derivative Contracts - Collars $ - $ - $ 293,847 $ 293,847
(59)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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.

 A reconciliation of the Company’s assets classified as Level 3 measurements is presented below.

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.

(a) At the end of each quarter, the Company assessed the carrying value of its producing 

properties for impairment. This assessment utilized estimates of future cash flows. Significant 

 judgments and assumptions in these assessments include estimates of future oil, NGL 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.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Year Ended September 30,

2012 2011

Fair Value Impairment Fair Value Impairment

Producing Properties $ 1,301,951 $ 826,508 $ 1,811,709 $ 1,728,162 (a)

 Derivatives

Balance of Level 3 as of October 1, 2011 $ 293,847

Total gains or (losses) - realized and unrealized:

 Included in earnings

 Realized 549,773

 Unrealized (940,557)

Included in other comprehensive income (loss) -

Purchases, issuances and settlements -

Transfers in and out of Level 3 -

Balance of Level 3 as of September 30, 2012 $ (96,937)
(60)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Depreciation, Depletion, Amortization and Impairment

Depreciation, depletion and amortization of the costs of producing oil and natural gas properties 

are generally computed using the unit-of-production method primarily on an individual property basis 

using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent 

Consulting Petroleum Engineer. The Company’s capitalized costs of drilling and equipping all 

development wells and those exploratory wells that have found proved reserves are amortized on a unitof-production basis over the remaining life of associated proved developed reserves. Lease costs are 

amortized on a unit-of-production basis over the remaining life of associated total proved reserves. 

Depreciation of furniture and fixtures is computed using the straight-line method over estimated 

productive lives of five to eight years.

Non-producing oil and natural gas properties include non-producing minerals, which had a net 

book value of $5,374,868 and $5,215,239 at September 30, 2012 and 2011, respectively, consisting of 

perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New 

Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have 

been accumulated over the 86-year life of the Company. There are approximately 198,965 net acres of 

non-producing minerals in more than 6,931 tracts owned by the Company. An average tract contains 

approximately 29 acres, and the average cost per acre is $45. Since inception, the Company has 

continually generated an interest in several thousand oil and natural gas wells using its ownership of the 

fee mineral acres as an ownership basis. There continues to be significant drilling activity each year on 

these mineral interests. Non-producing minerals are being amortized straight-line over a 33-year period. 

These assets are considered a long-term investment by the Company, as they do not expire (as do oil and 

natural gas leases). Given the above, it was concluded that a long-term amortization was appropriate and 

that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the 

minerals consist of a large number of properties, whose costs are not individually significant, and because 

virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate 

basis.

The Company recognizes impairment losses for long-lived assets when indicators of impairment 

are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The 

impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values 

are based on discounted cash flow as estimated by the Company’s Independent Consulting Petroleum 

Engineer. The Company’s estimate of fair value of its oil and natural gas properties at September 30, 

2012, is based on the best information available as of that date, including estimates of forward oil, NGL

and natural gas prices and costs. The Company’s oil and natural gas properties were reviewed for 

impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $826,508, 

$1,728,162 and $605,615, respectively, for 2012, 2011 and 2010. A significant reduction in oil, NGL and 

natural gas prices or a decline in reserve volumes would likely lead to additional impairment in future 

periods that may be material to the Company. 

Capitalized Interest

During 2012, 2011 and 2010, interest of $129,172, $0 and $104,100, respectively, was included in 

the Company’s capital expenditures. Interest of $127,970, $0 and $60,912, respectively, was charged to 

expense during those periods. Interest is capitalized using a weighted average interest rate based on the

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)
(61)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs 

and amortized using unit-of-production method.

Investments

Insignificant investments in partnerships and limited liability companies (LLC) that maintain 

specific ownership accounts for each investor and where the Company holds an interest of 5% or greater, 

but does not have control of the partnership or LLC, are accounted for using the equity method of 

accounting. 

Asset Retirement Obligations

The Company owns interests in oil and natural gas properties, which may require expenditures to 

plug and abandon the wells when the oil, NGL and natural gas reserves in the wells are depleted. The fair 

value of legal obligations to retire and remove long-lived assets is recorded in the period in which the 

obligation is incurred (typically when the asset is installed at the production location). When the liability 

is initially recorded, this cost is capitalized by increasing the carrying amount of the related properties 

and equipment. Over time the liability is increased for the change in its present value, and the capitalized 

cost in properties and equipment is depreciated over the useful life of the remaining asset. The Company 

does not have any assets restricted for the purpose of settling the asset retirement obligations. 

The following table shows the activity for the years ended September 30, 2012 and 2011, relating 

to the Company’s asset retirement obligations:

Environmental Costs

As the Company is directly involved in the extraction and use of natural resources, it is subject to 

various federal, state and local provisions regarding environmental and ecological matters. Compliance 

with these laws may necessitate significant capital outlays; however, to date the Company’s cost of 

compliance has been insignificant. The Company does not believe the existence of current environmental 

laws or interpretations thereof will materially hinder or adversely affect the Company’s business 

operations; however, there can be no assurances of future effects on the Company of new laws or 

interpretations thereof. Since the Company does not operate any wells where it owns an interest, actual 

compliance with environmental laws is controlled by others, with Panhandle being responsible for its 

proportionate share of the costs involved. Panhandle carries liability insurance and pollution control 

coverage. However, all risks are not insured due to the availability and cost of insurance.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

2012 2011

Asset Retirement Obligations as of beginning of the year $ 1,843,875 $ 1,730,369

Accretion of Discount 121,112 109,198

New Wells Placed on Production 184,027 28,624

Wells Sold or Plugged (26,064) (24,316)

Asset Retirement Obligations as of end of the year $ 2,122,950 $ 1,843,875
(62)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Environmental liabilities, which historically have not been material, are recognized when it is 

probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental 

liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2012 and 

2011, there were no such costs accrued.

Earnings (Loss) Per Share of Common Stock

Earnings (loss) per share is calculated using net income (loss) divided by the weighted average 

number of common shares outstanding, including unissued, vested directors’ shares during the period. 

The Company’s restricted stock awards are not included in the diluted earnings per share calculation 

because the effect would be non-dilutive.

Share-based Compensation

The Company recognizes current compensation costs for its Deferred Compensation Plan for 

Non-Employee Directors (the “Plan”). Compensation cost is recognized for the requisite directors’ fees 

as earned and unissued stock is added to each director’s account based on the fair market value of the 

stock at the date earned. The Plan’s structure is that 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. 

In accordance with guidance on accounting for employee stock ownership plans, the Company 

records as expense the fair market value of the stock at the time of contribution into its ESOP.

Restricted stock awards to certain officers provide for cliff vesting at the end of three or five years 

from the date of the awards. The fair value of the awards is ratably expensed over the vesting period in 

accordance with accounting guidance.

Income Taxes

The estimation of amounts of income tax to be recorded by the Company involves interpretation 

of complex tax laws and regulations, as well as the completion of complex calculations, including the 

determination of the Company’s percentage depletion deduction. Although the Company’s management 

believes its tax accruals are adequate, differences may occur in the future depending on the resolution of 

pending and new tax regulations. Deferred income taxes are computed using the liability method and are 

provided on all temporary differences between the financial basis and the tax basis of the Company’s 

assets and liabilities.

The threshold for recognizing the financial statement effect of a tax position is when it is more 

likely than not, based on the technical merits, that the position will be sustained by a taxing authority. 

Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that 

is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files 

income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory 

exceptions that allow for a possible extension of the assessment period, the Company is no longer subject 

to U.S. federal, state, and local income tax examinations for fiscal years prior to 2007.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)
(63)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The Company includes interest assessed by the taxing authorities in interest expense and penalties 

related to income taxes in general and administrative expense on its Statements of Operations. For fiscal 

September 30, 2012, 2011 and 2010, the Company recorded interest and penalties of $0, $21,000 and $0, 

respectively. The Company does not believe it has any significant uncertain tax positions.

New Accounting Standards

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.

Other accounting standards that have been issued or proposed by the FASB, or other standardssetting bodies, that do not require adoption until a future date are not expected to have a material impact 

on the financial statements upon adoption.

2. COMMITMENTS

The Company leases office space in Oklahoma City, Oklahoma, under the terms of an operating 

lease expiring in April 2015. Future minimum rental payments under the terms of the lease are $204,089 

in 2013, $204,089 in 2014 and $119,051 in 2015. Total rent expense incurred by the Company was 

$204,011 in 2012, $204,089 in 2011 and $203,939 in 2010.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)
(64)

3. INCOME TAXES

The Company’s provision (benefit) for income taxes is detailed as follows:

The difference between the provision (benefit) for income taxes and the amount which would 

result from the application of the federal statutory rate to income before provision (benefit) for income 

taxes is analyzed below for the years ended September 30:

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

2012 2011 2010

Provision (benefit) for income taxes at statutory rate $ 3,725,749 $ 4,090,069 $ 5,712,242

Percentage depletion (846,040) (733,516) (684,053)

State income taxes, net of federal provision (benefit) 464,677 (92,989) 325,000

State net operating loss valuation allowance (release) (31,000) 31,000 (278,000)

Other (39,386) (102,564) (174,189)

$ 3,274,000 $ 3,192,000 $ 4,901,000

 2012 2011 2010

Current:

Federal $ 1,452,000 $ 1,266,000 $ 3,950,000

State 20,000 48,000 174,000

 1,472,000 1,314,000 4,124,000

Deferred:

Federal 1,126,000 1,982,000 708,000

State 676,000 (104,000) 69,000

1,802,000 1,878,000 777,000

$ 3,274,000 $ 3,192,000 $ 4,901,000
(65)

3. INCOME TAXES (CONTINUED)

Deferred tax assets and liabilities, resulting from differences between the financial statement 

carrying amounts and the tax basis of assets and liabilities, consist of the following at September 30:

At September 30, 2012, the Company had an income tax benefit of $1,008,271 related to 

Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring from 2025 to 2031. The 

valuation allowance of $31,000 that was recorded in fiscal 2011 for the Oklahoma NOL’s was reversed 

in 2012 as management believes that they will be utilized before they expire. The AMT carry forwards 

do not have an expiration date.

4. LONG-TERM DEBT

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving 

loan with a limit in the amount of $80,000,000 which is subject to a semi-annual borrowing base 

determination, wherein BOK applies their own 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 risk 

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 $41,343,303 

at September 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 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 balance outstanding under the revolving loan was $14,874,985 

and $0 as of September 30, 2012 and 2011, respectively. At September 30, 2012, the effective interest 

rate was 2.36%.

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.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

2012 2011

Deferred tax liabilities:

Financial basis in excess of tax basis, principally

intangible drilling costs capitalized for financial

purposes and expensed for tax purposes $ 30,320,765 $ 26,939,720

Derivative contracts - 84,001

30,320,765 27,023,721

Deferred tax assets:

State net operating loss carry forwards, net of

valuation allowance of $0 in 2012 and $31,000 in 2011 1,008,271 1,130,732

AMT credit carry forwards 1,189,053 -

Deferred directors’ compensation 990,455 986,340

Statutory depletion carry forwards 415,958 -

Other 130,021 121 ,899

3,733,758 2,238,971

Net deferred tax liabilities $ 26,587,007 $ 24,784,750
(66)

4. LONG-TERM DEBT (CONTINUED)

The credit facility 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 September 

30, 2012, the Company was in compliance with the covenants of the credit facility.

5. SHAREHOLDERS’ EQUITY

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 

2010, the Board approved purchase 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. The Board’s 

approval included an initial authorization to purchase up to $1.5 million of Common Stock, with a 

provision for subsequent authorizations without specific action by the Board. As the amount of Common 

Stock purchased under any authorization reaches $1.5 million, another $1.5 million is automatically 

authorized for Common Stock purchases unless the Board determines otherwise. Pursuant to these 

resolutions adopted by the Board, the purchase of additional $1.5 million increments of the Company’s 

Common Stock became authorized and approved effective March 29, 2011, and March 14, 2012. As of 

September 30, 2012, $3,301,629 had been spent under the current program to purchase 116,578 shares. 

The shares are held in treasury and are accounted for using the cost method. On September 30 each year, 

treasury shares contributed to the Company’s ESOP on behalf of the ESOP participants were 10,660 in 

2012, 10,710 in 2011 and 11,632 in 2010.

6. EARNINGS PER SHARE

The following table sets forth the computation of earnings per share. 

7. EMPLOYEE STOCK OWNERSHIP PLAN

The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan 

that serves as the Company’s sole retirement plan for all its employees. Company contributions are made 

at the discretion of the Board and, to date, all contributions have been made in shares of Company 

Common Stock. The Company contributions are allocated to all ESOP participants in proportion to their 

compensation for the plan year, and 100% vesting occurs after three years of service. Any shares that do 

not vest are treated as forfeitures and are distributed amongst other vested employees. For contributions

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Year ended September 30,

2012 2011 2010

Numerator for basic and diluted earnings per share:

Net income (loss) $ 7,370,996 $ 8,493,912 $ 11,419,690

Denominator for basic and diluted earnings per share -

weighted average shares (including for 2012, 2011

and 2010, unissued, vested directors’ shares

of 114,596, 122,728 and 111,491, respectively) 8,360,931 8,393,890 8,422,387
(67)

7. EMPLOYEE STOCK OWNERSHIP PLAN (CONTINUED)

of Common Stock, the Company records as expense the fair market value of the stock at the time of 

contribution. The 267,723 shares of the Company’s Common Stock held by the plan, as of September 30, 

2012, are allocated to individual participant accounts, are included in the weighted average shares 

outstanding for purposes of earnings per share computations and receive dividends. 

Contributions to the plan consisted of:

8. DEFERRED COMPENSATION PLAN FOR DIRECTORS

The Panhandle Oil and Gas Inc. Deferred Compensation Plan for Non-Employee Directors (the 

“Plan”) provides that each eligible director can individually elect to receive shares of Company Common 

Stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee 

meeting fees. These shares are unissued and vest as earned. The shares are credited to each director’s 

deferred fee account at the closing market price of the stock on the date earned. As of September 30, 

2012, there were 121,348 shares (129,776 shares at September 30, 2011) included in the Plan. The 

deferred balance outstanding at September 30, 2012, under the Plan was $2,676,160 ($2,665,583 at 

September 30, 2011). Expenses totaling $417,347, $443,456 and $359,628 were charged to the 

Company’s results of operations for the years ended September 30, 2012, 2011 and 2010, respectively, 

and are included in general and administrative expense in the accompanying Statement of Operations. 

9. 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 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.

In June 2010, the Company began awarding shares of the Company’s Common Stock as restricted 

stock (non-performance based) to certain officers. The restricted stock vests at the end of the vesting 

period (three or five years) and contains nonforfeitable rights to receive dividends and voting rights 

during the vesting period. The fair value of the shares was based on the closing price of the shares on 

their award date and will be recognized as compensation expense ratably over the vesting period. Upon 

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

On December 21, 2010, the Company began awarding shares of the Company’s Common Stock, 

subject to certain share price performance standards (performance based), as restricted stock to certain 

officers. Vesting of these shares is based on the performance of the market price of the Common Stock

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Year Shares Amount

2012 10,660 $ 326,942

2011 10,710 $ 303,843

2010 11,632 $ 287,194
(68)

9. RESTRICTED STOCK PLAN (CONTINUED)

over the vesting period (three years). The fair value of the performance shares was estimated on the grant 

date using a Monte Carlo valuation model that factors in information, including the expected price 

volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life 

of the performance shares. Compensation expense for the performance shares is a fixed amount 

determined at the grant date and is recognized over the vesting period (three years) regardless of whether 

performance shares are awarded at the end of the vesting period. Upon vesting, shares are expected to be 

issued out of shares held in treasury.

Compensation expense for the restricted stock awards is recognized in G&A. 

The following table summarizes the Company’s pre-tax compensation expense for the years 

ended September 30, 2012, 2011 and 2010, related to the Company’s performance based and nonperformance based restricted stock.

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.

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

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Year Ended September 30,

2012 2011 2010

Performance based, restricted stock $ 150,480 $ 42,909 $ -

Non-performance based, restricted stock 180,443 109,573 12,028

Total compensation expense $ 330,923 $ 152,482 $ 12,028

As of September 30, 2012

Unrecognized Weighted

Compensation Average Period

Performance based, restricted stock $ 322,977 1.89

Non-performance based, restricted stock 370,587 2.05

Total $ 693,564
(69)

9. RESTRICTED STOCK PLAN (CONTINUED)

A summary of the status of unvested shares of restricted stock awards and changes is presented 

below:

10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

All oil and natural gas producing activities of the Company are conducted within the United 

States (principally in Oklahoma and Arkansas) and represent substantially all of the business activities of 

the Company.

The following table shows sales through various operators/purchasers during 2012, 2011 and 

2010.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Performance Weighted Nonbased Average Performance Weighted

Unvested Grant- based Unvested Average

Restricted Date Fair Restricted Grant-Date

Shares Value Shares Fair Value

Unvested shares as of

September 30, 2010 - $ - 8,500 $ 28.30

Granted 8,782 $ 19.54 8,780 $ 28.00

Vested - $ - - $ -

Forfeited - $ - - $ -

Unvested shares as of 8,782 $ 19.54 17,280 $ 28.15

September 30, 2011

Granted 17,709 $ 19.47 5,903 $ 31.55

Vested - $ - - $ -

Forfeited - $ - - $ -

Unvested shares as of 26,491 $ 19.49 23,183 $ 29.01

September 30, 2012

 2012 2011 2010

Southwestern Energy Company 15% 9% 8%

Chesapeake Operating, Inc. 13% 15% 14%

Devon Energy Corp. 10% 9% 6%

Newfield Exploration 7% 14% 15%

JMA Energy Company 5% 7% 11%
(70)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES 

(UNAUDITED)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of oil and natural gas properties and related 

accumulated depreciation, depletion and amortization as of September 30 is as follows:

Costs Incurred

For the years ended September 30, the Company incurred the following costs in oil and natural 

gas producing activities:

In 2012, $17.4 million of the property acquisition costs related to the acquisition of certain assets 

in the Arkansas Fayetteville Shale which closed on October 25, 2011. Approximately $3.9 million of 

2011 property acquisition costs relates to the acquisition of mineral acreage with proved reserves.

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

The following unaudited information regarding the Company’s oil, NGL and natural gas reserves 

is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis 

of geosciences and engineering data, can be estimated with reasonable certainty to be economically 

producible – from a given date forward, from known reservoirs, and under existing economic conditions, 

operating methods, and government regulations – prior to the time at which contracts providing the right 

to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether 

deterministic or probabilistic methods are used for the estimation. Existing economic conditions include 

prices and costs at which economic producibility from a reservoir is to be determined. The price shall be

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

2012 2011 2010

Property acquisition costs $ 20,404,465 $ 5,140,862 $ 742,005

Exploration costs 1,210,417 4,837,451 530,931

Development costs 24,578,943 17,310,808 10,685,088

$ 46,193,825 $ 27,289,121 $ 11,958,024

2012 2011

Producing properties $ 275,997,569 $ 230,554,198

Non-producing minerals 9,018,731 8,792,980

Non-producing leasehold 1,123,812 1,102,988

Exploratory wells in progress 8,018 1,204,382

286,148,130 241,654,548

Accumulated depreciation, depletion and amortization (164,652,199) (145,664,726)

Net capitalized costs $ 121,495,931 $ 95,989,822
(71)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES 

(UNAUDITED) (CONTINUED)

the average price during the 12-month period prior to the ending date of the period covered by the report, 

determined as an unweighted arithmetic average of the first-day-of-the-month price for each month 

within such period, unless prices are defined by contractual arrangements, excluding escalations based 

upon future conditions. The project to extract the hydrocarbons must have commenced or the operator 

must be reasonably certain that it will commence the project within a reasonable time. The area of the 

reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if 

any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to 

be continuous with it and to contain economically producible oil or natural gas on the basis of available 

geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir 

are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, 

engineering or performance data and reliable technology establishes a lower contact with reasonable 

certainty. Where direct observation from well penetrations has defined a highest known oil elevation and 

the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the 

structurally higher portions of the reservoir only if geoscience, engineering or performance data and 

reliable technology establish the higher contact with reasonable certainty. Reserves which can be 

produced economically through application of improved recovery techniques (including, but not limited 

to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project 

in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the 

operation of an installed program in the reservoir or an analogous reservoir, or other evidence using 

reliable technology establishes the reasonable certainty of the engineering analysis on which the project 

or program was based; and (ii) the project has been approved for development by all necessary parties 

and entities, including governmental entities.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of 

Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2012, 

2011 and 2010 (see Exhibits 23 and 99). 

The Company’s net proved oil, NGL and natural gas reserves, all of which are located in the 

United States, as of September 30, 2012, 2011 and 2010, have been estimated by the Company’s 

Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of 

appropriate geologic, petroleum engineering and evaluation principals and techniques that are in 

accordance with practices generally recognized by the petroleum industry as presented in the publication 

of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of 

Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of 

methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage 

of development, quality and completeness of basic data and production history.

All of the reserve estimates are reviewed and approved by our Vice President and COO, who 

reports directly to our President and CEO. Mr. Blanchard, our COO, holds a Bachelor of Science Degree

in Petroleum Engineering from the University of Oklahoma. Before joining the Company, he was sole 

proprietor of a consulting petroleum engineering firm, spent 10 years as Vice President of the MidContinent business unit of Range Resources Corporation and spent several years as an engineer with 

Enron Oil and Gas. He is an active member of the Society of Petroleum Engineers (SPE) with over 

26 years of oil and gas industry experience, including engineering assignments in several field locations.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)
(72)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES 

(UNAUDITED) (CONTINUED)

Our COO and internal staff work closely with our Independent Consulting Petroleum Engineers 

to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation 

process. We provide historical information to our Independent Consulting Petroleum 

Engineers for all properties such as ownership interest, oil and gas production, well test data, commodity 

prices, operating costs and handling fees, and development costs. Throughout the year, our team meets 

regularly with representatives of our Independent Consulting Petroleum Engineers to review properties 

and discuss methods and assumptions. 

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and 

the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir 

volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare 

these maps as well as to estimate representative values for porosity and water saturation. When adequate 

data was available and when circumstances justified, material balance and other engineering methods 

were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. 

These recovery factors were based on consideration of the type of energy inherent in the reservoirs, 

analyses of the petroleum, the structural positions of the properties and the production histories. When 

applicable, material balance and other engineering methods were used to estimate recovery factors. An 

analysis of reservoir performance, including production rate, reservoir pressure and gas-oil ratio 

behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in 

producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of 

appropriate decline curves or other performance relationships. In the analyses of production-decline 

curves, reserves were estimated only to the limits of economic production or to the limit of the 

production licenses as appropriate.

Accordingly, these estimates should be expected to change, and such changes could be material 

and occur in the near term as future information becomes available.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)
(73)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES 

(UNAUDITED) (CONTINUED)

Net quantities of proved, developed and undeveloped oil, NGL and natural gas reserves are 

summarized as follows:

(1) 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve 

volumes disclosure. These NGL are associated with the rapid increase in drilling activity in 

western Oklahoma and the Texas Panhandle, which includes many plays (horizontal Granite 

Wash, Hogshooter Wash, Cleveland, Marmaton, Tonkawa and the Anadarko Basin Woodford 

Shale) producing significant volumes of NGL.

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural 

gas, respectively, were as follows: September 30, 2012 - $89.41/Bbl, $35.70/Bbl, $2.51/Mcf ; September 

30, 2011 - $90.28/Bbl, $38.91/Bbl, $3.81/Mcf. The prices used to calculate reserves and future cash 

flows from reserves for oil and natural gas, respectively, were as follows: September 30, 2010 - 

$69.23/Bbl, $4.33/Mcf. 

The revisions of previous estimates from 2011 to 2012 were primarily the result of:

(1) Positive performance revisions of 3,613,707 Mcfe, of which 1,644,157 Mcfe were proved 

developed revisions principally attributable to properties in western Oklahoma. The

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Proved Reserves

Oil NGL (1) Natural Gas

(Barrels) (Barrels) (Mcf)

September 30, 2009 920,873 - 54,027,810

Revisions of previous estimates 47,999 - 15,762,883

Divestitures (487) - (7,778)

Extensions, discoveries and other additions 59,003 - 36,689,882

Production (102,379) - (8,302,342)

September 30, 2010 925,009 - 98,170,455

Revisions of previous estimates (59,360) 791,648 769,676

Acquisitions - - 3,189,520

Extensions, discoveries and other additions 82,230 - 8,005,990

Production (104,141) - (8,297,6572

September 30, 2011 843,738 791,648 101,837,984

Revisions of previous estimates 8,627 (76,794) (27,389,752)

Acquisitions - - 19,075,529

Extensions, discoveries and other additions 373,097 172,602 29,062,593

Production (153,143) (98,714) (9,072,298)

September 30, 2012 1,072,319 788,742 113,514,056
(74)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES 

(UNAUDITED) (CONTINUED)

remaining 1,969,550 Mcfe were proved undeveloped revisions principally attributable to 

higher proved reserves per well in the Company’s shale resource plays including the 

 Fayetteville Shale, Southeastern Oklahoma Woodford Shale and the Anadarko Basin 

 Woodford Shale.

(2) Negative gas pricing revisions of 31,412,464 Mcfe, which included 7,073,763 Mcfe of 

negative revisions due to proved developed wells reaching their economic limits earlier than 

previously projected due to current product prices. Negative revisions of 24,338,701 Mcfe 

were due to certain proved undeveloped locations, primarily in the Fayetteville Shale, 

 Southeastern Oklahoma Woodford Shale and the Anadarko Basin Woodford Shale, becoming 

 uneconomic at current product prices.

Extensions, discoveries and other additions from 2011 to 2012 are principally attributable to: 

(1) The Company’s ongoing development of conventional oil, NGL and natural gas plays 

utilizing horizontal drilling, including the Granite Wash and Cleveland plays in western 

Oklahoma and the Texas Panhandle, as well as the Marmaton and Tonkawa plays in western 

 Oklahoma. 

(2) The Company’s ongoing development of unconventional natural gas plays utilizing 

 horizontal drilling, including the Arkansas Fayetteville Shale and to a much lesser extent, the 

 Southeastern Oklahoma Woodford Shale.

(3) The Company’s ongoing development of unconventional oil, NGL and natural gas plays 

 utilizing horizontal drilling, in the Anadarko Basin Woodford Shale and Ardmore Basin 

Woodford Shale in western and southern Oklahoma.

(4) The Company’s ongoing development of conventional oil plays utilizing vertical drilling, in 

 the Mississippian play in northern Oklahoma, the Spraberry play in West Texas and the Yeso 

play in southeastern New Mexico.

(5) PUD additions principally in the Fayetteville Shale play in Arkansas and the Anadarko Basin 

Woodford Shale play in western Oklahoma.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

 Proved Developed Reserves Proved Undeveloped Reserves

 Oil NGL Natural Gas Oil NGL Natural Gas

 (Barrels) (Barrels) (Mcf) (Barrels) (Barrels) (Mcf)

September 30, 2010 861,240 - 57,344,190 63,769 - 40,826,265

September 30, 2011 759,989 386,774 60,193,878 83,749 404,874 41,644,106

September 30, 2012 849,548 494,160 65,733,119 222,771 294,582 47,780,937
(75)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES 

(UNAUDITED) (CONTINUED)

The following details the changes in proved undeveloped reserves for 2012 (Mcfe):

The beginning PUD reserves were 44.6 Bcfe. A total of 5.4 Bcfe (12% of the beginning balance) 

were transferred to proved developed producing during 2012. An additional 24.3 Bcfe (55% of the 

beginning balance) were removed during 2012 as the result of becoming uneconomic at 2012 prices 

(revisions due to pricing). A total of 29.7 Bcfe (67% of the beginning balance) of PUD reserves were 

moved out of the category during 2012 as either the result of being transferred to proved developed or 

removed as uneconomic. Only one PUD location from 2008, representing 1% of total 2012 PUD reserves 

remains in the PUD category while 45 PUD locations from 2009, representing 11% of total 2012 PUD 

reserves remain in the PUD category. The 46 PUD locations from 2008 and 2009 represent 8% of the 

Company’s current total of 589 PUD locations. We anticipate that all the Company’s PUD locations will 

be drilled and converted to PDP within five years of the date they were added. However, in the event that 

there are undrilled PUD locations at the end of the five year period, it is our intent to remove the reserves 

associated with those locations from our proved reserves as revisions.

Standardized Measure of Discounted Future Net Cash Flows

Accounting Standards prescribe guidelines for computing a standardized measure of future net 

cash flows and changes therein relating to estimated proved reserves. The Company has followed these 

guidelines, which are briefly discussed below. 

Future cash inflows and future production and development costs are determined by applying the 

trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices 

and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future 

prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of 

the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are 

made of quantities of proved reserves and the future periods during which they are expected to be 

produced based on continuation of the economic conditions applied for such year.

Estimated future income taxes are computed using current statutory income tax rates including 

consideration for the current tax basis of the properties and related carry forwards, giving effect to 

permanent differences and tax credits. The resulting future net cash flows are reduced to present value 

amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized 

measure are those prescribed by the FASB and, as such, do not necessarily reflect our expectations of 

actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the 

reserve quantity estimation process, as discussed previously, are equally applicable to the standardized 

measure computations since these estimates reflect the valuation process.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Beginning proved undeveloped reserves 44,575,844

Proved undeveloped reserves transferred to proved developed (5,393,421)

Revisions (22,369,152)

Extensions and discoveries 24,458,980

Purchases 9,612,804

Ending proved undeveloped reserves 50,885,055
(76)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES 

(UNAUDITED) (CONTINUED)

Changes in the standardized measure of discounted future net cash flow are as follows:

12. 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.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

2012 2011 2010

Beginning of year $ 78,382,434 $ 72,500,409 $ 53,746,508

Changes resulting from:

Sales of oil, NGL and natural gas, net of production costs (30,226,927) (33,570,621) (34,429,083)

Net change in sales prices and production costs (45,178,377) (2,697,833) 30,806,970

Net change in future development costs 4,618,147 4,177,910 (26,093,254)

Net change in asset retirement obligation (134,604) (51,098) (48,185)

Extensions and discoveries 34,216,533 11,938,029 53,274,047

Revisions of quantity estimates (27,419,576) 7,046,873 28,946,810

Acquisitions (divestitures) of reserves-in-place 20,160,327 4,480,858 (15,706)

Accretion of discount 13,644,203 12,523,091 8,066,959

Net change in income taxes 10,735,694 (5,329,092) (25,807,417)

Change in timing and other, net 8,616,434 7,363,908 (15,947,240)

Net change (10,968,146) 5,882,025 18,753 ,901

End of year $ 67,414,288 $ 78,382,434 $ 72,500,409

2012 2011 2010

Future cash inflows $ 408,694,869 $ 494,523,456 $ 489,691,155

Future production costs (135,516,703) (146,168,829) (148,727,914)

Future development costs (33,167,310) (43,425,811) (52,975,820)

Asset retirement obligation (2,122,950) (1,843,875) (1,730,369)

Future income tax expense (83,543,516) (107,111,317) (99,118,090)

Future net cash flows 154,344,390 195,973,624 187,138,962

10% annual discount (86,930,102) (117,591,190) (114,638,553)

Standardized measure of discounted

future net cash flows $ 67,414,288 $ 78,382,434 $ 72,500,409
(77)

12. ACQUISITIONS (CONTINUED)

Actual and Pro Forma Impact of Acquisitions (Unaudited)

Revenue attributable to this acquisition included in the Company’s Statement of Operations for 

the year ended September 30, 2012, was $3,434,850. Net income attributable to the acquisition included 

in the Statement of Operations for the year ended September 30, 2012, was $200,158.

Presented below is the unaudited pro forma financial information assuming the Company had 

acquired this business on October 1, 2010. 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. The pro forma financial information was not provided for the 

comparative period ending September 30, 2010, as the information could not be obtained from the seller.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

For the Year Ended

September 30

2012 2011

Revenue:

As reported $ 48,532,317 $ 44,976,651

Pro forma revenue 409,988 4,433,282

Pro forma $ 48,942,305 $ 49,409,933

Net Income:

As reported $ 7,370,996 $ 8,493,912

Pro forma income 136,315 644,859

Pro forma $ 7,507,311 $ 9,138,771
(78)

13. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

The following is a summary of the Company’s unaudited quarterly results of operations.

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

Fiscal 2012

Quarter Ended

December 31 March 31 June 30 September 30

Revenues $ 13,404,333 $ 10,436,910 $ 13,649,692 $ 11,041,382

Income (loss) before provision

for income taxes $ 4,261,110 $ 1,205,966 $ 4,681,299 $ 496,621

Net income (loss) $ 3,412,110 $ 675,966 $ 3,100,299 $ 182,621

Earnings (loss) per share $ 0.41 $ 0.08 $ 0.37 $ 0.02

Fiscal 2011

Quarter Ended

December 31 March 31 June 30 September 30

Revenues $ 9,901,548 $ 10,977,459 $ 11,688,417 $ 12,409,227

Income (loss) before provision

for income taxes $ 2,002,849 $ 2,271,253 $ 3,691,429 $ 3,720,381

Net income (loss) $ 1,426,849 $ 1,772,253 $ 2,650,429 $ 2,644,381

Earnings (loss) per share $ 0.17 $ 0.21 $ 0.32 $ 0.31
(79)

ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON 

 ACCOUNTING AND FINANCIAL DISCLOSURE

NONE

ITEM 9A CONTROLS AND PROCEDURES

(a) EVALUATION OF DISCLOSURE 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 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.

(b) MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Company’s management is responsible for establishing and maintaining adequate “internal 

control over financial reporting,” as such term is defined in Exchange Act Rule 13a-15(f). The 

Company’s management, including the President/CEO and Vice President/CFO, conducted an evaluation 

of the effectiveness of its internal control over financial reporting based on the Internal Control – 

Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway 

Commission. Based on the results of this evaluation, the Company’s management concluded that its 

internal control over financial reporting was effective as of September 30, 2012.

 (c) CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

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 ended September 30, 2012, or subsequent to the date 

the assessment was completed.

ITEM 9B OTHER INFORMATION

None
(80)

PART III

The information called for by Part III of Form 10-K (Item 10 – Directors and Executive Officers 

of the Registrant, Item 11 – Executive Compensation, Item 12 – Security Ownership of Certain 

Beneficial Owners and Management and Related Stockholder Matters, Item 13 – Certain Relationships 

and Related Transactions, and Item 14 – Principal Accountant Fees and Services), is incorporated by 

reference from the Company’s definitive proxy statement, which will be filed with the SEC within 120 

days after the end of the fiscal year to which this report relates.

PART IV

ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

FINANCIAL STATEMENT SCHEDULES

The Company has omitted all schedules because the conditions requiring their filing do not exist 

or because the required information appears in the Company’s Financial Statements, including the notes 

to those statements.

EXHIBITS

(3) Amended Certificate of Incorporation (incorporated by reference to Exhibit attached

to Form 10 filed January 27, 1980, and to Forms 8-K dated June 1, 1982, December 3,

1982, to Form 10-QSB dated March 31, 1999, and to Form 10-Q dated March 31, 2007)

By-Laws as amended (incorporated by reference to Form 8-K dated October 31, 1994)

By-Laws as amended (incorporated by reference to Form 8-K dated February 24, 2006)

By-Laws as amended (incorporated by reference to Form 8-K dated October 29, 2008)

By-Laws as amended (incorporated by reference to Form 8-K dated August 2, 2011)

(4) Instruments defining the rights of security holders (incorporated by reference to 

Certificate of Incorporation and By-Laws listed above)

*(10.1)Agreement indemnifying directors and officers (incorporated by reference to 

Form 10-K dated September 30, 1989, and Form 8-K dated June 15, 2007)

*(10.2)Agreements to provide certain severance payments and benefits to executive officers 

should a Change-in-Control occur as defined by the agreements (incorporated by reference 

to Form 8-K dated September 4, 2007)

(23) Consent of DeGolyer and MacNaughton, Independent Petroleum Engineering Consultants

(31.1) Certification of Chief Executive Officer

(31.2) Certification of Chief Financial Officer

(32.1) Certification of Chief Executive Officer

(32.2) Certification of Chief Financial Officer

(99) Report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consultants

(101.INS) XBRL Instance Document

(101.SCH) XBRL Taxonomy Extension Schema Document

(101.CAL) XBRL Taxonomy Extension Calculation Linkbase Document

(101.LAB) XBRL Taxonomy Extension Labels Linkbase Document

(101.PRE) XBRL Taxonomy Extension Presentation Linkbase Document

(101.DEF) XBRL Taxonomy Extension Definition Linkbase Document

* Indicates management contract or compensatory plan or arrangement
(81)

REPORTS ON FORM 8-K

No Form 8-K’s were filed in the fourth quarter of 2012.

SIGNATURES

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant 

caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

PANHANDLE OIL AND GAS INC.

By: /s/ Michael C. Coffman By: /s/ Lonnie J. Lowry

Michael C. Coffman Lonnie J. Lowry

President; Vice President;

Chief Executive Officer Chief Financial Officer

Date: December 11, 2012 Date: December 11, 2012

By: /s/ Robb P. Winfield

Robb P. Winfield

Controller; 

Chief Accounting Officer

Date: December 11, 2012

In accordance with the Securities Exchange Act of 1934, this report has been signed below by the 

following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ Bruce M. Bell /s/ Duke R. Ligon 

Bruce M. Bell, Director Duke R. Ligon, Director

Date December 11, 2012 Date December 11, 2012 

/s/ Robert O. Lorenz /s/ Robert A. Reece 

Robert O. Lorenz, Lead Independent Director Robert A. Reece, Director

 

Date December 11, 2012 Date December 11, 2012

/s/ Robert E. Robotti /s/ Darryl G. Smette 

Robert E. Robotti, Director Darryl G. Smette, Director

Date December 11, 2012 Date December 11, 2012

/s/ H. Grant Swartzwelder

H. Grant Swartzwelder, Director

Date December 11, 2012
(82)

EXHIBIT 23

November 12, 2012

Panhandle Oil and Gas Inc.

Grand Centre, Suite 300

5400 North Grand Blvd.

Oklahoma City, OK 73112

Ladies and Gentlemen:

We hereby consent to the use of the name DeGolyer and MacNaughton, to the

inclusion of our Letter Report, dated October 1, 2012, as attached as Exhibit 99 to the 

Annual Report on Form 10-K of Panhandle Oil and Gas Inc., and to the inclusion of 

information from “Appraisal Report as of September 30, 2012 on Certain Properties 

owned by Panhandle Oil and Gas Inc.” in the sections “Proved Reserves,” and 

“Supplementary Information on Oil and Natural Gas Reserves (Unaudited)” in the 

Annual Report on Form 10-K of Panhandle Oil and Gas Inc.

 Very truly yours,

 /s/DeGolyer and MacNaughton

 DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

DeGolyer And MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244
(83)

CERTIFICATION

I, Michael C. Coffman, certify that:

1. I have reviewed this annual report on Form 10-K of Panhandle Oil and Gas Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to 

state a material fact necessary to make the statements made, in light of the circumstances under which 

such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this 

report, fairly present in all material respects the financial condition, results of operations and cash 

flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining 

disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and 

internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) 

 for the registrant and have:

a). designed such disclosure controls and procedures, or caused such disclosure controls and 

 procedures to be designed under our supervision, to ensure that material information relating 

to the registrant, including its consolidated subsidiaries, is made known to us by others within 

those entities, particularly during the period in which this report is being prepared;

b). designed such internal control over financial reporting, or caused such internal control over 

financial reporting to be designed under our supervision, to provide reasonable assurance 

regarding the reliability of financial reporting and the preparation of financial statements for 

external purposes in accordance with generally accepted accounting principles;

c). evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented 

 in this report our conclusions about the effectiveness of the disclosure controls and procedures, 

 as of the end of the period covered by this report based on such evaluation; and

d). disclosed in this report any change in the registrant’s internal control over financial reporting 

that occurred during the registrant’s most recent fiscal quarter that has materially affected, or 

is reasonably likely to materially affect, the registrant’s internal control over financial 

 reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of 

internal control over financial reporting, to the registrant’s auditors and the audit committee of the 

registrant’s board of directors (or persons performing the equivalent functions):

a). all significant deficiencies and material weaknesses in the design or operation of internal 

control over financial reporting which are reasonably likely to adversely affect the registrant’s 

ability to record, process, summarize and report financial information; and

b). any fraud, whether or not material, that involves management or other employees who have a 

significant role in the registrant’s internal control over financial reporting.

/s/ Michael C. Coffman

Michael C. Coffman

Chief Executive Officer

Date: December 11, 2012

EXHIBIT 31.1
(84)

CERTIFICATION

I, Lonnie J. Lowry, certify that:

1. I have reviewed this annual report on Form 10-K of Panhandle Oil and Gas Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to 

state a material fact necessary to make the statements made, in light of the circumstances under which 

such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this 

report, fairly present in all material respects the financial condition, results of operations and cash 

flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining 

disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and 

internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) 

 for the registrant and have:

a). designed such disclosure controls and procedures, or caused such disclosure controls and 

 procedures to be designed under our supervision, to ensure that material information relating 

to the registrant, including its consolidated subsidiaries, is made known to us by others within 

those entities, particularly during the period in which this report is being prepared;

b). designed such internal control over financial reporting, or caused such internal control over 

financial reporting to be designed under our supervision, to provide reasonable assurance 

regarding the reliability of financial reporting and the preparation of financial statements for 

external purposes in accordance with generally accepted accounting principles;

c). evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented 

 in this report our conclusions about the effectiveness of the disclosure controls and procedures, 

 as of the end of the period covered by this report based on such evaluation; and

d). disclosed in this report any change in the registrant’s internal control over financial reporting 

that occurred during the registrant’s most recent fiscal quarter that has materially affected, or 

is reasonably likely to materially affect, the registrant’s internal control over financial 

 reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of 

internal control over financial reporting, to the registrant’s auditors and the audit committee of the 

registrant’s board of directors (or persons performing the equivalent functions):

a). all significant deficiencies and material weaknesses in the design or operation of internal 

control over financial reporting which are reasonably likely to adversely affect the registrant’s 

ability to record, process, summarize and report financial information; and

b). any fraud, whether or not material, that involves management or other employees who have a 

significant role in the registrant’s internal control over financial reporting.

/s/ Lonnie J. Lowry

Lonnie J. Lowry

Chief Financial Officer

Date: December 11, 2012

EXHIBIT 31.2
(85)

EXHIBIT 32.1

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK 73112

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Michael C. Coffman, President and Chief Executive Officer of Panhandle Oil and Gas Inc. (the 

“Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the 

Sarbanes-Oxley Act of 2002, hereby certify in connection with the Company’s Annual Report on Form 

10-K for the period that ended September 30, 2012, as filed with the Securities and Exchange 

Commission (the “Report”) that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange 

 Act of 1934; and

(2) The information contained in this Report fairly presents, in all material respects, the financial 

 condition and results of operations of the Company.

/s/ Michael C. Coffman

Michael C. Coffman

President & 

Chief Executive Officer

December 11, 2012
(86)

EXHIBIT 32.2

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK 73112

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Lonnie J. Lowry, Vice President and Chief Financial Officer of Panhandle Oil and Gas Inc. (the 

“Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the 

Sarbanes-Oxley Act of 2002, hereby certify in connection with the Company’s Annual Report on Form 

10-K for the period that ended September 30, 2012, as filed with the Securities and Exchange 

Commission (the “Report”) that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange 

 Act of 1934; and

(2) The information contained in this Report fairly presents, in all material respects, the financial 

 condition and results of operations of the Company.

/s/ Lonnie J. Lowry

Lonnie J. Lowry

Vice President & 

Chief Financial Officer

December 11, 2012

5400 N. Grand Blvd., Suite 300

Oklahoma City, Oklahoma 73112

Phone: 405.948.1560

Fax: 405.948.1063

www.panhandleoilandgas.com

001CSN3515