UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K
Annual Report under Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended September 30,2002 --------------------------------------------2003Commission File Number: 0-9116
PANHANDLE ROYALTY COMPANY
------------------------- (Exact(Exact name of registrant as specified in its charter)OKLAHOMA 73-1055775 ------------------------------ ----------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization ) Identification No.) Grand Centre, Suite 210, 5400 N. Grand Blvd., Oklahoma City, OK 73112 - -------------------------------------------------------------------------------- (Address of principal executive offices) (Zip code) Registrant's
OKLAHOMA 73-1055775 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
Grand Centre, Suite 210, 5400 North 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:
NONE ----
CLASS A COMMON STOCK (VOTING) AMERICAN 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 A COMMON STOCK (VOTING) .0333 par value ----------------------------- --------------- (Title of Class)CLASS B COMMON STOCK (NON-VOTING) $1.00 par value
--------------------------------- ---------------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 during the past 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[X] Yes [ ] No
--- ---Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K
ss. 229.045 of this chapter)is not contained herein, and will not be contained, to the best ofregistrant'sregistrant’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.{X}[X]Indicated by check mark whether the registrant is an accelerated filer (as defined in Rule 126-2 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'sregistrant’s common stock, atDecember 4, 2002,March 31, 2003, was$28,313,933.$31,122,979. As of December 4,2002, 2,079,1002003, 2,089,101 shares of Class A Common stock were outstanding.DOCUMENTS INCORPORATED BY REFERENCE ProxyDocuments Incorporated By Reference
The definitive proxy statement for the
registrant'sregistrant’s annual meeting of shareholders to be held in20032004 (to be filed within 120 days of the close ofregistrant'sregistrant’s fiscal year) is incorporated by reference into PartIII.T A B L E O F C O N T E N T SIII, hereof.TABLE OF CONTENTSTABLE OF CONTENTS
Page PART I Item 1. Business................................................................................. 2-51Business 1-4 Item 2. Properties...............................................................................2Properties 5-10 Item 3.3Legal Proceedings........................................................................Proceedings10 Item 4.4Submission of Matters to a Vote of Security Holders...................................... 11Holders10 PART II - -------Item 5.5Market for Registrants Common Equity and Related Stockholder Matters..................... 11Matters10-11 Item 6.6Selected Financial Data.................................................................. 12Data11-12 Item 7. Management's7Management’s Discussion and Analysis of Financial Condition and Results of Operations....Operations12-17 Item 7A. Quantitive7AQuantitative and Qualitative DisclosureDisclosures about MarketRisk..................................Risk17 Item 8.8Financial Statements and Supplementary Data.............................................. 18-43Data17-42 Item 9.9Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..... 44Disclosure43 Item 9A Controls and Procedures 43 PART III - --------Item 10.-13.10-14Incorporated by Reference to Proxy Statement PART IV - -------Item 14. Controls and Procedures.................................................................. 44 Item 15.15Exhibits, Financial Statement Schedules and Reports on Form 8- K......................... 44K43 Signature Page.............................................................................................. 45 Certifications Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.............................................................. 46-47Page44 Exhibit 21.................................................................................................. 481045-56 Exhibit 99.1................................................................................................ 492157 Exhibit 99.2................................................................................................ 5031.1-31.258-59 Exhibit 32.1-32.2 60-61 As used in this report,
"SEC"“SEC” means the United States Securities and Exchange Commission,"Bbl"“Bbl” means barrel,"Mcf"“Mcf” means thousand cubic feet,"Mcf/D"“Mcf/D” means thousand cubic feet per day,"Mcfe"“Mcfe” means natural gas stated on an MCF basis and crude oil converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil to six Mcf of natural gas,"PV-10"“PV-10” means estimated pretax present value of future net revenues discounted at 10% using SEC rules,"gross"“gross” wells or acres are the wells or acres in which the Company has a working interest, and"net"“net” wells or acres are determined by multiplying gross wells or acres by theCompany'sCompany’s net revenue interest in such wells or acres.References to years 2001-2004 refer to the Company’s fiscal years ended September 30, each year. PART I
ITEM
1.1 BUSINESSGENERAL
Panhandle Royalty Company
("Panhandle"(“Panhandle” or the"Company"“Company”) is an Oklahoma Corporation, organized in 1926 as Panhandle Cooperative Royalty Company. In 1979, Panhandle Cooperative Royalty Company was merged into Panhandle Royalty Company.Panhandle'sPanhandle’s authorized and registered stock consisted of 100,000 shares of $1.00 par value Class A common stock. In 1982, the Company split the stock on a 10-for-1 basis and reduced the par value to $.10, resulting in 1,000,000 shares of authorized Class A Common stock. In May 1999, theCompany'sCompany’s shareholders voted to increase the authorized Class A Common stock of the Company to 6,000,000 shares and to split the shares on a three-for-one basis. In addition, voting rights for the shares were changed from one vote per shareholder to one vote per share.Since its formation, the Company has been involved in the acquisition and management of mineral interests and the exploration for, and development of, oil and gas properties, principally involving wells located on the
Company'sCompany’s mineral interests.Panhandle'sPanhandle’s mineral properties and other oil and gas interests are located primarily in Oklahoma, New Mexico and Texas. Properties are also located intwentynineteen other states. The majority of theCompany'sCompany’s oil and gas production is from wells located in Oklahoma and New Mexico. In 1988, the Company merged with New Mexico Osage Royalty Company, thus acquiring most of its New Mexico mineral interests.On October 1, 2001, Panhandle acquired privately held Wood Oil Company (Wood) of Tulsa, Oklahoma. The acquisition was made pursuant to an Agreement and Plan of Merger among Panhandle Royalty Company, PHC, Inc., and Wood, dated August 9, 2001. Wood merged with
Panhandle'sPanhandle’s wholly owned subsidiary PHC, Inc., on October 1, 2001, with Wood being the surviving Company. Prior to the acquisition, Wood was a privately held company engaged in oil and gas exploration and production and fee mineral ownership and owned interests in certain oil and gas and real estate partnerships and an office building in Tulsa. Wood is operating as a subsidiary of Panhandle. Wood and its shareholders were unrelated parties to Panhandle.The
Company'sCompany’s office is located at Grand Centre Suite 210, 5400N.North Grand Blvd., Oklahoma City, OK 73112 (405)948-1560, FAX (405)948-2038. Its website is located at www.panra.com.BUSINESS STRATEGY
The majority of
Panhandle'sPanhandle’s revenues are derived from the production and sale of oil and natural gas. See"Item“Item 8-— FinancialStatements"Statements”. TheCompany'sCompany’s oil and gas holdings, including its mineral interests and its interests in producing wells, both working interests and royalty interests, are centered in Oklahoma with activity, in recent years, in New Mexico and Texas. See"Item“Item 2-— Description ofProperties"Properties”. Exploration and development of theCompany'sCompany’s oil and gas properties are conducted in association with operating oil and gas companies, including major and independent companies. The Company does not operate any of its oil and gas properties. The Company has been an active participant forseveralmany years in wells drilled on theCompany'sCompany’s mineral properties and in third party drilling prospects. A large percentage of theCompany'sCompany’s recent drilling participations have been on properties in which the Company has mineral interests and in many cases already owns an interest in a producing well in the unit. This"increased density"“increased density” drilling has accounted for amajoritylarge part of the successful oil and gas wells(1)
completed during these years and has added significant reserves for the Company. The Company acquired additional mineral interest properties, both producing and non-producing and interests in approximately 2000 wells in the Wood acquisition. Several of the mineral properties and well interests were in areas where the Company had no mineral holdings, thus expanding the
Company'sCompany’s area of interest.2PRINCIPAL PRODUCTS AND MARKETS
The
Company'sCompany’s principal products are crude oil and natural gas. These products are sold to various purchasers, including pipeline and marketing companies, which are generally located in and service the areas where theCompany'sCompany’s producing wells are located. The Company does not act as operator for any of the properties in which it owns an interest, thus it relies on the operating expertise of numerous companies that operate in the area where the Company owns mineral interests. This expertise includes drilling operations and completions, producing well operations and, in some cases, the marketing or purchasing of thewell'swell’s production. Natural gas sales are principally handled by the well operator and are normally contracted on a monthly basis with third party gas marketers and pipeline companies. Payment for gas sold is received either from the contracted purchasers or the well operator. Crude oil sales are generally handled by the well operator and payment for oil sold is received from the well operator or from the crude oil purchaser.In general, prices of oil and gas are dependent on numerous factors beyond the control of the Company, such as competition, international events and circumstances (including 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'sCompany’s natural gas are subject to seasonal variations.COMPETITIVE BUSINESS CONDITIONS
The oil and gas industry is highly competitive, particularly in the search for new oil and gas reserves. There are many factors affecting
Panhandle'sPanhandle’s competitive position and the market for its products which are beyond its control. Some of these factors are the quantity and price of foreign oil imports, changes in prices received for its oil and gas production, business and consumer demand for refined oil products and natural gas, and the effects of federal and state regulation of the exploration, production and sales of oil and natural gas. Changes in existing economic conditions, weather patterns and actions taken by OPEC and other oil-producing countries have dramatic influence on the price Panhandle receives for its oil and gas production. The Company relies heavily on companies with greater resources, staff, equipment, research, and experience for operation of wells and the development and drilling of subsurface prospects. The Company uses its strong financial base and its mineral property ownership, coupled withit'sit’s own geologic and economic evaluation to participate in drilling operations with these larger companies. This method allows the Company to effectively compete in drilling operations it could not undertake on its own due to financial and personnel limits and allows it to maintain low overhead costs.SOURCES AND AVAILABILITY OF RAW MATERIALS
The existence of commercial oil and gas reserves is essential to the ultimate realization of value from the
Company'sCompany’s mineral properties and these mineral properties may be considered a raw material to its business. The production and sale of oil and natural gas from theCompany'sCompany’s oil and gas properties is essential to provide the cash flow necessary to sustain the ongoing viability of the Company.(2)
The Company continues to reinvest a portion of its cash flow in the purchase of oil and gas leasehold acreage and additional mineral properties 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 and gas. This participation in exploration and production and the purchasing of additional mineral interests will continue to supply the Company with the raw materials with which to generate additional cash flow. Mineral and leasehold purchases are made from varied owners, and the Company does not rely on any particular companies or individuals for these acquisitions.
MAJOR CUSTOMERS
The
Company'sCompany’s oil and gas production is sold by the well operators, in most cases, to many different purchasers on a well-by-well basis. During fiscal2002,2003, sales to ONEOK, through well operators, accounted for approximately17%14% of theCompany'sCompany’s total revenues. Generally, if one purchaser declines to continue purchasing theCompany'sCompany’s oil and/or natural gas, several other purchasers can be located, especially in the current market environment for natural gas. Pricing is usually reasonably consistent from purchaser to purchaser.3PATENTS, TRADEMARKS, LICENSES, FRANCHISES AND ROYALTY AGREEMENTS
The Company does not own any patents, trademarks, licenses or franchises. Royalty agreements on producing oil and gas wells stemming from the
Company'sCompany’s ownership of mineral interests generate a substantial portion of theCompany'sCompany’s revenues. These royalties are tied to the ownership of the mineral interests and this ownership is perpetual, unless sold by the Company. Royalties are due and payable to the Company whenever oil and/or gas is produced from wells located on theCompany'sCompany’s mineral properties.GOVERNMENTAL REGULATION
Oil and gas production is subject to various taxes, such as gross production taxes and, in some cases, ad valorem taxes.
The State of Oklahoma and other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells. These statutes and regulations currently limit the rate at which oil and gas can be produced from certain of the
Company'sCompany’s properties. As previously discussed, the well operators are relied upon by Panhandle to comply with governmental regulations.Various aspects of the
Company'sCompany’s oil and gas operations are regulated by agencies of the federal government. The transportation of natural gas in interstatecommencecommerce is generally regulated by the Federal Energy Regulatory Commission (FERC) pursuant to the Natural Gas Act of 1938 (the NGA) 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.In the past, the federal government regulated the prices at which the
Company'sCompany’s produced oil and gas could be sold. Currently,"first sales"“first sales” of natural gas by producers and marketers, and all sales of crude oil, condensate and natural gas liquids, can be made at uncontrolled market prices, but Congress could reenact price controls at any time.(3)
Within the past decade, the FERC has issued numerous orders and policy statements designed to create a more competitive environment in the national natural gas marketplace, including orders promoting
"open access"“open access” transportation on natural gas pipelines subject to theFERC'sFERC’s NGA and NGPA jurisdiction. TheFERC's "Order 636"FERC’s “Order 636” was issued in April 1992 and was designed to restructure the interstate natural gas transportation and marketing system and to promote competition within all phases of the natural gas industry. Among other things, Order 636 required interstate pipelines to separate the transportation of gas from the sale of gas, to change the manner in which pipeline rates were designed and to implement other changes intended to promote the growth of market centers. Subsequent FERC initiatives have attempted to standardize interstate pipeline business practices and to allow pipelines to implement market-based, negotiated and incentive rates. The restructured services implemented by Order 636 and successor orders have now been in effect for a number of winter heating seasons and have significantly affected the manner in which natural gas (both domestic and foreign) is transported and sold to consumers.FERC has indicated that it remains committed to Order
636's "fundamental goal"636’s “fundamental goal” of"improving“improving the competitive structure of the natural gas industry in order to maximize the benefits of wellhead decontrol,"” the future regulatory goals and priorities of FERC may change, and it is not possible to predict the effect, if any, of future restructuring orders or policies on theCompany'sCompany’s operations.Federal tax law
allowshas allowed producers of"tight gas"“tight gas” to utilize an approximate $.52/MMBTU tax credit for gas produced from approved wells. The creditiswas a direct reduction of regular federal income tax. Panhandle began receiving revenues from"tight gas"“tight gas” wells during fiscal 1992. This creditwill bewas available for all tight gas sold prior to January 1,2003, and is expected to reduce the Company's cash outlay for income taxes. 42003. While Order 636 and related orders do not directly regulate either the production or sale of gas that may be produced from the
Company'sCompany’s properties, the increased competition and changes in business practices within the natural gas industry resulting from such orders have affected the terms and conditions under which the Company markets and transports its available gas supplies. To date, theFERC'sFERC’s pro-competition policies have not materially affected theCompany'sCompany’s business or operations. On a prospective basis, however, such orders may substantially increase the burden on producers and transporters to accurately nominate and deliver on a daily basis specified volumes of natural gas, or to bear penalties or increased costs in the event scheduled deliveries are not made.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 provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays, however, to date the
Company'sCompany’s cost of compliance has been insignificant. The Company does not believe the existence of these environmental laws will materially hinder or adversely affect theCompany'sCompany’s business operations; however, there can be no assurances of future events. 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 to the extent available at reasonable cost, pollution control coverage. However, all risks are not insured due to the availability and cost of insurance.EMPLOYEES
At September 30,
2002,2003, Panhandle employedfourteenfifteen persons on a full-time basis and has no part-time employees. Three of the employees are executive officers and one is also a director of the Company.(4)
ITEM
2.2 PROPERTIESAs of September 30,
2002, Panhandle's2003, Panhandle’s principal properties consisted of perpetual ownership of260,035259,390 net mineral acres, held principally in tracts in Oklahoma, New MexicoOklahomaand Texas and 19 other states. The Company also held leases on16,18320,227 net acres of minerals in Louisiana, Oklahoma and Texas. At September 30,2002,2003, Panhandle held small royalty and/or working interests in4,7084,898 producing oil or gas wells,96of which 98 were successfully completed but not yet producing wells, and6160 wells in the process of being drilled or completed.5Panhandle does not have current abstracts or title opinions on all mineral properties owned and, therefore, cannot warrant that it has unencumbered title to all of its properties. In recent years, few challenges have been made against the
Company'sCompany’s fee title to its properties.Panhandle pays ad valorem taxes on its minerals owned in Arkansas, Colorado, Idaho, Indiana, Illinois, Kansas, Tennessee and Texas.
ACREAGE
The following table of mineral interests owned reflects, as of September 30,
2002,2003, 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).MINERAL INTERESTS
Net Gross Net Gross Net Gross Net Gross Acres Acres Acres Acres Acres Acres Acres Acres Prod’g Prod’g Leased Leased Open Open State (1) (1) (2) (2) (3) (3) Alabama 5 479 5 479 Arkansas 10,050 44,636 1,068 2,756 8,982 41,880 Colorado 8,327 39,299 109 219 8,217 39,080 Florida 6,901 13,849 6,901 13,849 Idaho 30 880 30 880 Illinois 1,068 5,038 40 320 1,028 4,718 Indiana 27 262 27 262 Kansas 3,122 11,976 110 880 3,012 11,096 Louisiana 17 17 17 17 Missouri 355 430 355 430 Mississippi 150 740 150 740 Montana 1,008 17,947 1,008 17,947 Nebraska 1,319 13,249 1,319 13,249 North Dakota 11,179 64,286 11,179 64,286 New Mexico 57,456 172,879 1,365 6,200 140 560 55,951 166,119 Oklahoma 113,146 949,467 27,914 201,465 1,538 3,167 83,693 737,608 Oregon 72 2,187 72 2,187 South Dakota 1,825 9,300 1,825 9,300 Tennessee 40 500 40 500 Texas 43,085 361,017 6,889 76,999 172 1,901 36,025 282,117 Utah 160 320 160 320 Washington 50 298 50 298 259,390 1,709,054 37,495 288,839 1,850 5,628 220,045 1,407,361
Net Gross Net Gross Net Gross Net Gross Acres Acres Acres Acres Acres Acres Acres Acres Prod'g Prod'g Leased Leased Open Open STATE(1) (1)“Producing” represents the mineral acres in which Panhandle owns a royalty or working interest in a producing well. (2) (2)“Leased” represents the mineral acres, owned by Panhandle, that are leased to third parties but not producing. (3) (3) - ------------------------------------------------------------------------------------------------------------------------Arkansas 10,050 44,320 1,065 2,519 157 880 8,828 40,921 Colorado 8,327 39,299 109 219 8,217 39,080 Florida 6,924 13,849 6,924 13,849 Illinois 1,068 4,979 33 260 1,035 4,719 Kansas 3,122 11,976 120 960 3,002 11,016 Montana 1,008 17,947 1,008 17,947 Nebraska 1,319 13,249 7 160 1,312 13,089 North Dakota 11,179 64,286 11,179 64,286 New Mexico 57,456 172,879 1,295 5,350 1,916 5,190 54,245 162,339 Oklahoma 112,842 875,717 27,838 195,491 3,221 28,331 81,783 651,895 South Dakota 1,825 9,300 1,825 9,300 Tennessee 1,584 3,587 1,584 3,587 Texas 42,467 352,348 6,737 73,445 290 2,815 35,440 276,088 Others 864 5,613 864 5,612 - ------------------------------------------------------------------------------------------------------------------------ TOTAL: 260,035 1,629,348 37,197 278,244 5,591 37,376 217,246 1,313,728(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"“Open” represents mineral acres owned by Panhandle that are not leased or in production. (5)
The following table reflects net mineral acres leased from others, lease expiration dates, and net leased acres held by production.
LEASES
Net Acres Net Net Lease Acres Held by State Acres Expiring Production - ------------------------------------------------------------------------------------------------------- 2003 2004 2005 ---------------- ----------------- ----------------Kansas 973 -- -- -- 973 Oklahoma 14,188 2,542 1,993 154 9,429 Texas 350 40 -- -- 310 New Mexico 476 -- -- -- 476 Other 196 -- -- -- 196 - ------------------------------------------------------------------------------------------------------- TOTAL 16,183 2,582 1,993 154 11,3846
Net Acres Net Lease Acres Held by State Acres Expiring Production 2004 2005 2006 Kansas 2,117 — — — 2,117 Oklahoma 15,984 1,976 715 1,183 12,110 Texas 304 — — — 304 New Mexico 494 — — — 494 Other 1,328 — — — 1,328 TOTAL 20,227 1,976 715 1,183 16,353 PROVED RESERVES
The following table summarizes estimates of the proved reserves of oil and gas held by Panhandle. All reserves are located within the United States. Because the
Company'sCompany’s non-producing mineral and leasehold interests consist of various small interests in numerous tracts located primarily in Oklahoma, New Mexico and Texas and because the Company is a non-operator and must rely on third parties to propose and drill wells, it is not feasible to provide estimates of all proved undeveloped reserves and associated future net revenues. Prior to fiscal 1995, the Company did not provide estimates of any proved undeveloped reserves. The Company directs its independent petroleum engineering firm to include proved undeveloped reserves in certain significant areasof Oklahoma and New Mexicoin the scope of properties evaluated for the Company. The Company,in both cases,expects drilling to continue in these areas for the next several years, and thus made the decision to provide proved undeveloped reserve estimates for these areas. All reserve quantity estimates were prepared by Campbell & Associates, Inc., an independent petroleum engineering firm. TheCompany'sCompany’s reserve estimates were not filed with any other federal agency.
Proved Developed Reserves Barrels of Oil MCF of Gas ------------------------- -------------- ----------September 30, 2002 820,790 24,089,830 September 30, 2001 412,705 13,236,455 September 30, 2000 408,732 11,585,331 Proved Undeveloped Reserves September 30, 2002 294,415 5,219,570 September 30, 2001 263,386 4,451,895 September 30, 2000 251,508 2,803,789 Total Proved Reserves September 30, 2002 1,115,205 29,309,400 September 30, 2001 676,091 17,688,350 September 30, 2000 660,240 14,389,120
Barrels of Oil MCF of Gas Proved Developed Reserves September 30, 2003 703,400 23,599,473 September 30, 2002 820,790 22,896,330 September 30, 2001 412,705 13,236,455 Proved Undeveloped Reserves September 30, 2003 132,575 4,670,400 September 30, 2002 294,415 5,219,570 September 30, 2001 263,386 4,451,895 Total Proved Reserves September 30, 2003 835,978 28,269,873 September 30, 2002 1,115,205 28,115,900 September 30, 2001 676,091 17,688,350 (6)
The major portion of the increase in total proved reserves at September 30, 2002 and 2003, as compared to September 30, 2001, is due to the addition of Wood Oil
Company'sCompany’s reserves. At September 30, 2002Wood'sand 2003, respectively, Wood’s total proved reserves were 521,442 barrels and 9,803,280 mcf and 368,831 barrels and 9,324,613 mcf. These reserves are net ofoil and 10,996,780 mcfapproximately 1.2 mmcf ofgas.CO2 gas reserves owned by Wood Oil Company.Because the determination of reserves is a function of testing, evaluating, developing oil and gas reservoirs and establishing a production decline history, along with product price fluctuations, it would be expected that estimates will change as future information concerning those reservoirs is developed and as market conditions change. Estimated reserve quantities and future net revenues are affected by changes in product prices, and these prices have varied substantially in recent years. Proved developed reserves are those expected to be recovered through existing well bores under existing economic and operating conditions. Proved undeveloped reserves are reserves that may be recovered from undrilled acreage, but are usually limited to those sites directly offsetting established production units and have sufficient geological data to indicate a reasonable expectation of commercial success.
ESTIMATED FUTURE NET REVENUES
Set forth below are estimated future net
revenuescash flows with respect toPanhandle'sPanhandle’s proved reserves (based on the estimated units set forth in the immediately preceding table) as of year ends, and the present value of such estimated future netrevenues,cash flows, computed by applying a ten (10) percent discount factor as required by the rules and regulations of the Securities and Exchange Commission. Estimated future netrevenuescash flows have been computed by applying current year-end prices to future production of proved reserves less estimated future expenditures (based on costs as of year end) to be incurred with respect to the development and production of such reserves. Such pricing is based on SEC guidelines. No federal income taxes are included in estimated costs. However, the amounts are net of operating costs and production taxes levied by respective states. Prices used for determining7future revenuescash flows from oil and natural gas for the periods ended September 30, 2003, 2002, 2001and 2000were as follows: 2003 - $27.39, $4.43; 2002 - $27.76, $3.12; 2001 - $24.03,$1.81; 2000 - $32.84, $3.96.$1.81. These future netrevenuescash flows should not be construed as the fair market value of theCompany'sCompany’s reserves. A market value determination would need to include many additional factors, including anticipated oil and gas price increases or decreases.Estimated Future Net
RevenuesCash Flows
9-30-02 9-30-01 9-30-00 ----------- ----------- -----------Proved Developed $76,081,978 $25,797,780 $48,481,740 Proved Undeveloped $18,572,672 $10,141,828 $16,604,661 ----------- ----------- ----------- Total Proved (1) $94,654,650 $35,939,608 $65,086,401
9-30-03 9-30-02 9-30-01 Proved Developed $ 97,847,582 $ 76,081,978 $ 25,797,780 Proved Undeveloped $ 17,893,760 $ 18,572,672 $ 10,141,828 Total Proved (1) $ 115,741,342 $ 94,654,650 $ 35,939,608 10% Discounted Present Value of Estimated Future Net
RevenuesCash Flows
9-30-03 9-30-02 9-30-01 Proved Developed $ 63,591,623 $ 49,485,409 $ 17,533,672 Proved Undeveloped $ 11,905,681 $ 11,868,812 $ 6,589,021 Total Proved (1) $ 75,497,304 $ 61,354,221 $ 24,122,693
9-30-02 9-30-01 9-30-00 ----------- ----------- -----------Proved Developed $49,485,409 $17,533,672 $32,122,191 Proved Undeveloped $11,868,812 $ 6,589,021 $11,417,769 ----------- ----------- ----------- Total Proved(1) $61,354,221 $24,122,693 $43,539,960The increase from September 30, 2001 to September 30, 2002 and 2003 is primarily attributable to the addition of reserves from Wood Oil Company and the increased oil and gas prices used in the 2002 and 2003 reserve report (see above listed prices). (1) The major portion of the decrease from September 30, 2000 to September 30, 2001, is attributable to the decreased oil and gas prices used in the 2001 reserve report as compared to the prices used in the 2000 reserve report. The increase from September 30, 2001 to September 30, 2002 is attributable to the addition of reserves from Wood Oil Company, the increased oil and gas prices used in the 2002 reserve report (see above listed prices), and new reserve additions from drilling.(7)
OIL AND GAS PRODUCTION
The following table sets forth the
Company'sCompany’s net production of oil and gas for the fiscal periods indicated.
Year Year Year Ended Ended Ended 9-30-02 9-30-01 9-30-00 --------- --------- ---------Bbls - Oil 132,514 68,530 66,609 MCF - Gas 3,897,084 2,208,238 2,454,844
Year Year Year Ended Ended Ended 9-30-03 9-30-02 9-30-01 Bbls - - Oil 112,746 132,514 68,530 MCF - Gas 3,926,124 3,897,084 2,208,238 The increase in production volumes from September 30, 2001 to September 30, 2002 and 2003 was substantially due to the production of 1,582,277 mcf and 74,294 barrels and 1,510,206 mcf and 69,243 barrels from the Wood Oil
properties. 8properties, respectively. Average Sales Prices and Production Costs
The following table sets forth unit price and cost data for the fiscal periods indicated.
Year Year Year Ended Ended Ended Average Sales Price 9-30-02 9-30-01 9-30-00 ------------------- ----------- ---------- -----------Per Bbl. Oil $ 22.48 $ 28.16 $ 27.13 Per MCF Gas $ 2.59 $ 4.81 $ 3.03
Year Year Year Ended Ended Ended Average Sales Price 9-30-03 9-30-02 9-30-01 Per Bbl. Oil $ 29.30 $ 22.48 $ 28.16 Per MCF Gas $ 4.79 $ 2.59 $ 4.81 Average Production (Lifting Cost)
(Per
(Per MCFE of Gas)
(1) $ .46 $ .36 $ .27 (2) $ .41 $ .28 $ .41 $ .87 $ .64 $ .68
(1) $ .36 $ .27 $ .17Includes actual well operating costs only. (2) $ .28 $ .41 $ .34 -------------- ------------ ------------- $ .64 $ .68 $ .51Includes production taxes, compression, handling and marketing fees paid on natural gas sales and other minor expenses associated with well operations. (1) Includes actual well operating costs only. (2) Includes production taxes, compression, handling and marketing fees paid on natural gas sales, and other minor expenses associated with well operations. Average well operating costs are influenced by the fact that the Company bears no cost of production on many of its well interests.A substantial number of the
Company'sCompany’s producing well interests are royalty interests, which bear no share of the operating costs.GROSS AND NET PRODUCTIVE WELLS AND DEVELOPED ACRES
The following table sets forth
Panhandle'sPanhandle’s gross and net productive oil and gas wells as of September 30,2002.2003. Panhandle owns fractional royalty interests or fractional working interests in these wells. The Company does not operate any wells.
Gross Wells Net Wells ----------- ---------Oil 953 28.587649 Gas 3,755 73.834639 ----- ---------- TOTAL 4,708 102.422288
Gross Wells Net Wells Oil 957 25.876996 Gas 3,941 78.647848 TOTAL 4,898 104.524844 Information on multiple completions is not available from
Panhandle'sPanhandle’s records, but the number of such is insignificant.(8)
As of September 30,
2002,2003, Panhandle owned278,244288,839 gross developed mineral acres and37,19737,495 net developed mineral acres. Panhandle has also leased from others204,894149,841 gross developed acres which contain11,38416,353 net developed acres.UNDEVELOPED ACREAGE
As of September 30,
2002,2003, Panhandle owned1,351,1041,420,215 gross and222,838221,895 net undeveloped mineral acres, and leases on55,52469,260 gross and4,7793,874 net acres.DRILLING ACTIVITY
The following net productive development and exploratory wells and net dry development and exploratory wells, in which the Company had a fractional royalty or working interest, were drilled and completed during the fiscal years indicated. Also shown are the net wells purchased during these periods.
9
Net Productive Net Dry Development Wells Wells Wells - ----------------- ---------------- -------Fiscal year ending September 30, 2000 2.356519 .277873 Fiscal year ending September 30, 2001 4.568279 .969404 Fiscal year ending September 30, 2002 4.059870 1.146157 Exploratory Wells Fiscal year ending September 30, 2000 .810099 .400511 Fiscal year ending September 30, 2001 1.806223 .676206 Fiscal year ending September 30, 2002 1.416253 .550419 Purchased Wells Fiscal year ending September 30, 2000 .007321 0 Fiscal year ending September 30, 2001 .040365 0 Fiscal year ending September 30, 2002 53.246100 0
Net Productive Net Dry Wells Wells Development Wells Fiscal year ending September 30, 2001 4.568279 .969404 Fiscal year ending September 30, 2002 4.059870 1.146157 Fiscal year ending September 30, 2003 4.986539 .462544 Exploratory Wells Fiscal year ending September 30, 2001 1.806223 .676206 Fiscal year ending September 30, 2002 1.416253 .550419 Fiscal year ending September 30, 2003 1.117805 .541950 Purchased Wells Fiscal year ending September 30, 2001 .040365 0 Fiscal year ending September 30, 2002 53.246100 0 Fiscal year ending September 30, 2003 .113069 0 (9)
PRESENT ACTIVITIES
The following table sets forth the gross and net oil and gas wells drilling or testing as of September 30,
2002,2003, in which Panhandle owns a royalty or working interest.
Gross Wells Net Wells ----------- ---------Oil 6 .130980 Gas 55 1.546280
Gross Wells Net Wells Oil 7 .108641 Gas 53 1.730527 OTHER FACILITIES
The Company leases approximately
7,6008,189 square feet of office space in Oklahoma City, OK. The obligation under this lease will end in2003.2008.ITEM
3.3 LEGAL PROCEEDINGSThere were no material legal proceedings involving Panhandle or its subsidiary, as of the date of this report.
10ITEM
4.4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSNo matters were submitted to a vote of
Panhandle'sPanhandle’s security holders during the fourth quarter of the fiscal year ended September 30,2002.2003.PART II
ITEM
5.5 MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERSThe
Company'sCompany’s common stock is listed on theNASDAQ Small-Cap MarketAmerican Stock Exchange (symbolPANRA)PHX). The following table sets forth the high and low trade prices of theCompany'sCompany’s common stock during the periods indicated:
Quarter Ended HIGH LOW ----------------- -------- --------December 31, 2000 $ 14.000 $ 12.250 March 31, 2001 $ 19.563 $ 13.250 June 30, 2001 $ 23.000 $ 18.050 September 30, 2001 $ 19.010 $ 15.160 December 31, 2001 $ 18.000 $ 14.700 March 31, 2002 $ 15.15 $ 14.350 June 30, 2002 $ 15.900 $ 14.000 September 30, 2002 $ 14.950 $ 12.750
Quarter Ended HIGH LOW December 31, 2001 $ 18.00 $ 14.70 March 31, 2002 $ 15.15 $ 14.35 June 30, 2002 $ 15.90 $ 14.00 September 30, 2002 $ 14.95 $ 12.75 December 31, 2002 $ 20.20 $ 12.00 March 31, 2003 $ 18.13 $ 15.25 June 30, 2003 $ 23.84 $ 14.94 September 30, 2003 $ 23.91 $ 21.40 As of December 4,
2002,2003, the approximate number of holders of shares of Panhandle stockwere:was:
Title of Class Number of Holders -------------- -----------------Class A Common (Voting) ..................2,700 (10)
During the past two years, cash dividends have been paid as follows on the class A common stock:
DATE RATE PER SHARE ---- --------------December 2000 $ .07 March 2001 $ .14 June 2001 $ .07 September 2001 $ .07December 2001 $ .07 March 2002 $ .07 June 2002 $ .07 September 2002 $ .07 December 2002 $ .07 March 2003 $ .07 June 2003 $ .07 September 2003 $ .07 The
Company'sCompany’s line of credit loan agreement contains a provision limiting the paying or declaring of a cash dividend to fifty percent of cash flow, as defined, of the preceding twelve-month period. See Note 4 to the consolidated financial statements contained herein at"Item“Item 8-— FinancialStatements"Statements”, for a further discussion of the loan agreement.11ITEM
6.6 SELECTED FINANCIAL DATAThe following table summarizes consolidated financial data of the Company and should be read in conjunction with the
"Management's“Management’s Discussion and Analysis of Financial Condition and Results ofOperations"Operations” and the Consolidated Financial Statements of the Company, including the Notes thereto, included elsewhere in this report.
Year Ended September 30, 2002 (A) 2001 2000 1999 1998REVENUES Oil & Gas Sales $ 13,080,754 $ 12,546,055 $ 9,091,920 $ 5,077,240 $ 5,337,832 Lease Bonuses 41,497 17,991 82,030 10,773 44,269 Interest & Other 469,146 231,876 104,024 29,462 58,081 $ 13,591,397 $ 12,795,922 $ 9,277,974 $ 5,117,475 $ 5,440,182 COSTS & EXPENSES Lease Oper. Exp. & Prod. Taxes $ 3,001,449 $ 1,771,789 $ 1,458,935 $ 963,804 $ 961,929 Exploration Costs (B) 417,971 947,046 514,739 535,431 481,244 Depr. Depl. Amortization 5,845,779 1,670,961 1,789,491 1,379,562 1,287,562 Provision for Impairment 1,116,234 848,535 262,998 357,891 149,851 Gen. & Administrative 2,263,908 1,689,426 1,450,241 1,164,745 1,099,636 Interest Expense 895,997 779 15,643 16,943 3,125 $ 13,541,338 $ 6,928,536 $ 5,492,047 $ 4,418,376 $ 3,983,347 Income Before Provision (Benefit) for Income Taxes $ 50,059 $ 5,867,386 $ 3,785,927 $ 699,099 1,456,835 Provision (Benefit) for Income Taxes (293,000) 1,600,000 925,000 (35,000) 142,000 Net Income $ 343,059 $ 4,267,386 $ 2,860,927 $ 734,099 $ 1,314,835 Diluted Earnings per Share $ .16 $ 2.05 $ 1.38 $ .36 $ .64 Dividends Declared per share $ .28 $ .35 $ .28 $ .27 $ .30 Weighted Average Shares Outstanding Basic 2,067,872 2,060,109 2,055,470 2,047,507 2,039,292 Diluted 2,089,972 2,085,044 2,077,430 2,063,906 2,052,366 Net Cash Provided By Operating Activities $ 7,481,195 $ 9,302,965 $ 5,366,066 $ 2,836,783 $ 3,458,521 Total Assets $ 44,837,068 $25,279,684 $16,210,327 $ 13,263,877 $13,019,312 Long-Term Debt $ 14,024,000 $ 4,050,000 $ 0 $ 0 $ 0 Shareholders Equity $ 16,953,294 $16,995,050 $13,353,814 $ 11,048,604 $10,804,243
Year Ended September 30, 2003 (A) 2002 (A) 2001 2000 1999 Oil & Gas Sales $ 22,098,198 $ 13,080,754 $ 12,546,055 $ 9,091,920 $ 5,077,240 Lease Bonuses 72,765 41,497 17,991 82,030 10,773 Interest & Other 285,075 469,146 231,876 104,024 29,462 $ 22,456,038 $ 13,591,397 $ 12,795,922 $ 9,277,974 $ 5,117,475 Lease Oper. Exp. & Prod. Taxes $ 4,013,572 $ 3,001,449 $ 1,771,789 $ 1,458,935 $ 963,804 Exploration Costs (B) 469,224 417,971 947,046 514,739 535,431 Depr. Depl. Amortization 5,783,457 5,845,779 1,670,961 1,789,491 1,379,562 Provision for Impairment 692,220 1,116,234 848,535 262,998 357,891 Gen. & Administrative 2,666,177 2,263,908 1,689,426 1,450,241 1,164,745 Interest Expense 699,266 895,997 779 15,643 16,943 $ 14,323,916 $ 13,541,338 $ 6,928,536 $ 5,492,047 $ 4,418,376 Income before Provision (Benefit) for Income Taxes $ 8,132,122 $ 50,059 $ 5,867,386 $ 3,785,927 $ 699,099 Cumulative effect of accounting changes, net of taxes of $28,500 (C) 46,500 — — — — Provision (Benefit) for Income Taxes 2,217,000 (293,000 ) 1,600,000 925,000 (35,000 ) Net Income $ 5,961,622 $ 343,059 $ 4,267,386 $ 2,860,927 $ 734,099 (11)
Year Ended September 30, 2003 (A) 2002 (A) 2001 2000 1999 Diluted Earnings per Share $ 2.83 $ .16 $ 2.05 $ 1.38 $ .36 Dividends Declared per share $ .28 $ .28 $ .35 $ .28 $ .27 Weighted Average Shares Outstanding Basic 2,081,372 2,067,872 2,060,109 2,055,470 2,047,507 Diluted 2,103,713 2,089,972 2,085,044 2,077,430 2,063,906 Net Cash Provided By Operating Activities $ 13,198,368 $ 7,481,195 $ 9,302,965 $ 5,366,066 $ 2,836,783 Total Assets $ 49,402,534 $ 44,837,068 $ 25,279,684 $ 16,210,327 $ 13,263,877 Long-Term Debt $ 12,666,661 $ 14,024,000 $ 4,050,000 $ 0 $ 0 Shareholders Equity $ 22,527,685 $ 16,953,294 $ 16,995,050 $ 13,353,814 $ 11,048,604 All share per share amounts, are adjusted for the effect of the 3-for-1 stock split which was effective May 7, 1999.
(A) 2002 and 2003 results included are consolidated amounts of Panhandle Royalty Company and wholly owned subsidiary Wood Oil Company, acquired October 1, 2001.
(B) The Company uses the successful efforts method of accounting for its oil and gas activities.
(C) Represents the income effect of the adoption of SFAS No. 143,Accounting for Asset Retirement Obligationson October 1, 2003. See Note 1: Summary of Significant Accounting Policies of Notes to the Condensed Consolidated Financial Statements for a complete discussion.
ITEM
7. MANAGEMENT'S7 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSForward-looking statements for 2002 and later periods are made throughout this document. Such statements represent estimates of management based on the Company's
Forward-looking statements for 2004 and later periods are made throughout this document. Such statements represent estimates of management based on the Company’s historical operating trends, its proved oil and gas reserves and other information currently available to management. The Company cautions that the forward-looking statements provided herein are subject to all the risks and uncertainties incident to the acquisition, development and marketing of, and exploration for oil and gas reserves. These risks include, but are not limited to oil and natural gas price risk, environmental risk, drilling risk, reserve quantity risk and operations and production risks. For all the above reasons, actual results may vary materially from the forward-looking statements and there is no assurance that the assumptions used are necessarily the most likely to occur. GENERAL
The
Company cautions that the forward-looking statements provided herein are subject to all the risks and uncertainties incident to the acquisition, development and marketing of, and exploration for oil and gas reserves. These risks include, but are not limited to oil and natural gas price risk, environmental risk, drilling 12risk, reserve quantity risk and operations and production risks. For all the above reasons, actual results may vary materially from the forward-looking statements and there is no assurance that the assumptions used are necessarily the most likely to occur. GENERAL The Company'sCompany’s principal line of business is the production and sale ofitsoil and naturalgas reserves.gas. Results of operations are dependent upon the quantity of production and the price obtained for such production. Prices received by the Company for the sale of its oil and natural gas have fluctuated significantly from period to period. Such fluctuations affect theCompany'sCompany’s ability to maintain or increase its production from existing oil and gas properties and to explore, develop or acquire new properties.The following table reflects certain operating data for the periods presented:
For the Year Ended September 30, 2002 2001 2000Production: Oil (bbls) 132,514 68,530 66,609 Gas (mcf) 3,897,084 2,208,238 2,454,844 Average Sales Price: Oil (per bbl) $ 22.48 $ 28.16 $ 27.13 Gas (per mcf) $ 2.59 $ 4.81 $ 3.03(12)
For the Year Ended September 30, 2003 2002 2001 Production: Oil (bbls) 112,746 132,514 68,530 Gas (mcf) 3,926,124 3,897,084 2,208,238 Average Sales Price: Oil (per bbl) $ 29.30 $ 22.48 $ 28.16 Gas (per mcf) $ 4.79 $ 2.59 $ 4.81 RESULTS OF OPERATIONS
2003 COMPARED TO 2002.REVENUES
Total revenues increased 65% to $22,456,038 in 2003 compared to $13,591,397 in 2002. The increase was due to a large increase in the average sales price for natural gas in 2002; offset some what by a 15% decrease in oil production volumes in 2003. Gas production volume was basically flat in 2003 compared to 2002. New production from the Company’s drilling activity replaced the normal decline of existing gas wells. Few oil wells have been drilled in recent years, thus, oil production continues to decline.
LEASE OPERATING EXPENSES AND PRODUCTION TAXES (LOE)
LOE continues to increase each year as the Company increases the number of working interest wells in which it has an interest. The Company participated in a record number of working interest wells in 2003. Gross production taxes are paid as a percentage of oil and gas sales revenues and thus increased substantially in 2003 due to the large increase in oil and gas sales revenues.
EXPLORATION COSTS
Exploration costs increased $51,253 or 12% in 2003 as compared to 2002. The increased costs were primarily dry hole costs. As previously mentioned, the Company participated in a record number of wells in 2003, several of which were exploratory. As the Company utilizes the successful efforts method of accounting for oil and gas operations, dry holes resulted in the expensing of all costs associated with those wells.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
DD&A declined $62,322 or 1% in 2003. The decline was principally due to decreased oil production volume in 2003; reducing the units of production DD&A on the Company’s oil properties.
PROVISION FOR IMPAIRMENT
The provision for impairment of the Company’s oil and gas properties decreased $424,014, or 38% in 2003. This decrease can be principally attributed to the higher market price for natural gas at year-end 2003 as compared to year-end 2002.
GENERAL AND ADMINISTRATIVE COSTS (G&A)
G&A costs increased $402,269 in 2003. Personnel related expenses (including salaries, payroll taxes, insurance expenses and ESOP expenses) increased approximately $137,000 in 2003. G&A expense related to the Non-Employee Directors Deferred Compensation Plan (“the Plan”) increased approximately $180,000 in 2003. This increase was a result of the Company recognizing a charge to
(13)
general and administrative expense to adjust the potential shares in the Plan to market price at September 30, 2003, versus a minimal charge in 2002 for the same adjustment. The Non-Employee directors have taken these potential shares, rather than a cash payment for their director’s fees. In addition, the Company incurred expenses of approximately $50,000 upon listing its shares on the American Stock Exchange in 2003.
INTEREST EXPENSE
Interest expense decreased $196,731 or 22% in 2003. The decrease was due to lower outstanding debt balances, and lower effective interest rates.
PROVISION FOR INCOME TAXES
The provision for income taxes increased in 2003, due to a much larger income before taxes (as discussed above). The Company continued to be able to utilize tax credits from production of “tight gas sands” natural gas and excess percentage depletion on its oil and gas properties to reduce its tax liability, and its effective tax rate from the federal and state statutory rates. The effective tax rate was approximately 27% in 2003 and 2001 while a tax benefit was provided in 2002.
OVERVIEW
The Company recorded a net income of $5,961,622 in 2003, compared to a net income of $343,059 in 2002. Total revenues were larger as a result of significantly increased oil and gas sales revenues generated by increases in the average sales prices of oil and natural gas in 2003 as compared to 2002.
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2003, the Company had positive working capital of $1,335,344 as compared to negative working capital of $2,399,457 at September 30, 2002. The increase in working capital from September 30, 2002 to September 30, 2003, is the result of increased oil and gas sales revenues during 2003, which is discussed in Results of Operation above, and the reduction in the current portion of long-term debt by $2,000,000. This reduction in the current portion of long-term debt is the result of the restructuring of the Company’s bank debt in March 2003. The fixed monthly principal payment on the bank debt was reduced from $333,000 to $166,667. For a further discussion of the Company’s bank debt see Note 4: Long Term Debt of Notes to the Condensed Consolidated Financial Statements contained here-in. Cash flow from operating activities increased 76% to $13,198,368 for fiscal 2003, as compared to fiscal 2002, primarily due to a significant increase in product sales prices.
Capital expenditures for oil and gas activities for 2003 amounted to $9,195,916, as compared to $6,967,767 for 2002, exclusive of $15,229,466 used to acquire Wood Oil Company.
The Company has historically funded its capital expenditures, overhead costs and dividend payments from operating cash flow. Due to the increased capital expenditure level in 2003, the Company borrowed, early in the year, $1,525,000 on its revolving bank loan to help fund those expenditures. As a result of the increased cash flow from higher prices received for natural gas in the last three quarters of fiscal 2003, the Company made total principal payments of $4,878,335 on its bank debt. The Company has approximately $7.8 million available credit under the bank debt facility which is in place, for capital expenditures, acquisitions or any combination of uses. Further, the credit facility could be increased, if needed, for a large acquisition.
2002 Compared To 2001
REVENUES
Total revenues increased 6% to $13,591,397 in 2002, compared to $12,795,922 in 2001. The increase was a direct result of increased sales volumes for both oil and natural gas offset by dramatically reduced
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sales prices for both oil and natural gas, as outlined in the above table. The increased sales volume of both oil and natural gas is almost exclusively due to the addition of production from the Wood Oil acquisition properties. Wood
Oil'sOil’s production volumes were 1,582,277 mcf (94% of the gas volume increase) and 74,294 barrels (100% of the oil volume increase). The reduction in average sales price was simply the result of world market conditions for crude oil and natural gas prices returning to more sustainable price levels from the ultra high prices of certain months in fiscal 2001.LEASE OPERATING EXPENSES AND PRODUCTION TAXES (LOE)
LOE increased $1,251,482 to $2,173,667 in 2002. 95% of the increase was due to LOE on the Wood acquisition properties. Gross production taxes are paid as a percentage of oil and gas sales revenues and thus fluctuate by increases in oil and gas sales revenues.
EXPLORATION COSTS
Exploration costs declined 56% in 2002 as fewer exploratory wells were drilled in 2002, thus, reducing the chance of an exploratory well being a dry hole, which under the successful
effectsefforts accounting method are expensed as exploration costs.DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
DD&A increased 250% in 2002 or $4,174,818. The majority of the increase, $3,099,085, was DD&A on the Wood acquisition properties. The DD&A on these properties was calculated using the fair value of the properties which was assigned in the purchase accounting done at the acquisition date. In addition, a full year of DD&A on many wells completed late in 2001 was recognized in 2002. Drilling and completion costs in fiscal 2001 were extremely high as drilling rigs and completion equipment enjoyed high utilization rates during the year. These high costs were thus being amortized in 2002.
13PROVISION FOR IMPAIRMENT
The provision for impairment of the Company’s oil and gas properties increased 32% or $267,699 in 2002. The increase is due again to the high costs of drilling and equipping wells in 2001 coupled with disappointing production volumes on several wells, resulting in impairment on those fields and several individual
wells.wells as those wells came on line in fiscal 2002.GENERAL AND ADMINISTRATIVE COSTS (G&A)
G&A increased $574,482 in 2002 or 34%. The majority of the increase was due to G&A associated with Wood Oil and the three employees retained from Wood. Additionally one other employee was hired during 2002
yearand personnel related expenses (including salaries, payroll taxes, insurance expense and ESOP expense) increasedinduring the year.INTEREST EXPENSE
Interest expense increased by $895,218 in 2002. The increase is due to interest paid on the loan used to acquire Wood Oil. The acquisition was funded by a new $20,000,000 five-year term loan which requires monthly principal and interest payments. At September 30, 2002 the interest rate on the term loan was 4.5%.
PROVISION FOR INCOME TAXES
The provision for income taxes decreased in 2002 due to a much lower income before taxes. The Company continues to be able to utilize tax credits from production of
"tight“tight gassands"sands” natural gas and excess percentage depletion on its oil and gas properties. The effective tax rate was approximately(15)
27% in 2001. The aggregate income tax benefit of $293,000 in 2002, was primarily a result of percentage depletion and
"tight“tight gassands"sands” credits reducing the expected federal income tax expense by approximately $279,000.OVERVIEW
The Company recorded a net income of $343,059 in 2002, compared to net income of $4,267,386 in 2001. This decrease was the result of lower oil and natural gas
naturalsales prices and increased LOE, DD&A, impairment, G&A and interest expense. The increased expenses, for the most part, were a result of the Wood Oil acquisition.2001 COMPARED TO 2000. REVENUES Total revenues increased 38% to $12,795,922 in 2001 compared to $9,277,974 in 2000. The increase was due to a large increase in the average sales price for natural gas in 2001, offset some what by a 10% decrease in gas production volumes in 2001. The decreased sales volumes were principally due to decreased sales from the Potato Hills Field in southeast Oklahoma, as normal production decline takes place. Additionally, nationwide gas storage facilities filled quickly as summer approached, limiting demand for natural gas in the summer months. LEASE OPERATING EXPENSES AND PRODUCTION TAXES (LOE) LOE continues to increase each year as the Company increases the number of working interest wells in which it has an interest. The Company participated in a record number of working interest wells in 2001. Gross production taxes are paid as a percentage of oil and gas sales revenues and thus fluctuate by increases in oil and gas sales revenues. EXPLORATION COSTS Exploration costs increased $432,307 or 84% in 2001 as compared to 2000. The increased costs were primarily dry hole costs. As previously mentioned, the Company participated in a record number of wells in 2001, many of which were exploratory. As the Company utilizes the successful efforts method of accounting for oil and gas operations, dry holes resulted in the expensing of all costs associated with those wells. 14DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A) DD&A declined $118,530 or 7% in 2001. The decline was principally due to decreased gas production volume in 2001, reducing the units of production DD&A on the Company's oil and gas properties. GENERAL AND ADMINISTRATIVE COSTS (G&A) G&A costs increased $239,185 in 2001. The increase was the result of the Company paying an investment banking firm $200,000 to provide a valuation of the Company, strategic planning and other advice. In addition, personnel related expenses (including salaries, payroll taxes, insurance expenses and ESOP expenses) increased approximately $98,000 in 2001. These increases were offset by a reduction in 2001 G&A expense related to the Non-Employee Directors Deferred Compensation Plan ("the Plan"). This decease was a result of the Company recognizing a charge to general and administrative expense of approximately $175,000 to adjust the potential shares in the Plan to market price at September 30, 2000, verses a comparable charge to expense of approximately $31,000 for 2001. The Non-Employee directors have taken these potential shares, rather than a cash payment for their directors fees. PROVISION FOR INCOME TAXES The provision for income taxes increased in 2001, due to a much larger income before taxes (as discussed above). The Company continued to be able to utilize tax credits from production of "tight gas sands" natural gas and excess percentage depletion on its oil and gas properties to reduce its tax liability, and an effective tax rate from the federal and state statutory rates. The effective tax rate was approximately 27% in 2001 and 24% in 2000. LIQUIDITY AND CAPITAL RESOURCES At September 30, 2002, the Company had a working capital deficit of $2,399,457 as compared to $1,044,334 at September 30, 2001. The decrease is the result of the $3,996,000 current portion of the $20,000,000 term loan used to fund the acquisition of Wood Oil Company on October 1, 2001. Monthly payments on the term loan of $333,000, plus, accrued interest began on December 1, 2001. Cash provided by operating activities was $7,481,195 for 2002, $9,302,965 for 2001 and $5,366,066 for 2000. The Company's expenditures for oil and gas activities for 2002 amounted to $6,937,687, exclusive of $15,229,466 used to acquire Wood Oil Company. In 2001, these expenditures amounted to $9,481,077 and in 2000 were $4,070,865. These expenditures are discretionary and increased in 2001 as prices for both oil and gas increased causing a substantial increase in the number of wells being drilled, thus, increasing the actual costs of drilling and completing wells. The decrease in 2002, resulted from dramatically decreased oil and gas prices, thus, causing an industry wide reduction in the number of wells being drilled which reduced the costs of drilling and equiping wells. Historically, the Company has funded its capital expenditures, overhead expenditures and dividend payments from operating cash flow. With the addition of the monthly payments required on the term loan, the Company has utilized (as of December 4, 2002), $2,000,000 of the $5,000,000 line-of-credit to help fund these expenditures. Management expects to borrow additional funds under the line-of-credit during the coming fiscal year, as needs arise, to help fund drilling costs. Currently, cash provided from operating activities is expected to increase in 2003, as prices received for natural gas sales are projected to exceed the 2002 prices. However, capital expenditures are also projected to be increased over 2002 levels. The Company has the potential availability of equity, which could be offered in a public or private placement, if additional capital were needed for capital expenditures or for debt reduction.CRITICAL ACCOUNTING POLICIES
Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates,
judgementsjudgments 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 theCompany'sCompany’s reported cash15flows or liquidity. Generally, accounting rules do not involve a selection among alternatives, but involve a selection of the appropriate policies for applying the basic principles. Interpretation of the existing rules must be done and judgementsjudgments made on how the specifics of a given rule apply to the Company.The more significant reporting areas impacted by
management's judgementsmanagement’s judgments and estimates are crude oil and natural gas reserve estimation, impairment of assets and tax accruals.Management's judgementsManagement’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.OIL AND GAS RESERVES
Of these
judgementsjudgments and estimates, management considers the estimation of crude oil and natural gas reserves to be the most significant. Changes in crude oil and natural gas reserve estimates affect theCompany'sCompany’s calculation of depreciation and depletion, provision for abandonment and assessment of the need for asset impairments. TheCompany'sCompany’s consulting engineer with assistance from Company geologists prepares estimates of crude oil 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. As required by the guidelines and definitions established by the Securities and Exchange Commission, these estimates are based on current crude oil and natural gas pricing. As previously discussed, crude oil and natural gas prices are volatile and largely affected by worldwide consumption and are outside the control of management. Projected future crude oil and natural gas pricing assumptions are used by management to prepare estimates of crude oil and natural gas reserves used in formulating managements overall operating decisions in the exploration and production segment.SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
The Company has elected to utilize the successful efforts method of accounting for its oil and 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 developmental dry holes are capitalized and amortized by field using the unit-of-production method as oil and gas is produced. The accounting method may yield significantly different operating results than the full cost method.
(16)
IMPAIRMENT OF ASSETS
All long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its future net cash flows. The evaluations involve a significant amount of
judgementjudgment since the results are based on estimated future events, such as inflation rates, future sales prices for oil and gas, future costs to produce these products, estimates of future oil and gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test apropertyfield for impairment may result from significant declines in sales prices or unfavorable adjustments to oil and gas reserves. 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.TAX ACCRUALS
The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations. Although the
Company'sCompany’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters.16The above description of the
Company'sCompany’s critical accounting policies is not intended to be an all-inclusive discussion of the uncertainties considered and estimates made by management in applying 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.ITEM
7. A.7 A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKThe
Company'sCompany’s results of operations and operating cash flows are impacted by changes in market prices for oil and gas. Operations and cash flows are also impacted by changes in the market interest rates related to the revolving credit facilityand the $20 million five-year term loan, both bearingwhich bears interest at an annual variable interest rate equal to the national prime rate minus?%-3/4% or LIBOR for one, three or six month periods, plus 1.8%.AAt September 30, 2003 a one percent change in the prime interest rate would result in approximately a$180,000$55,000 change in annual interest expense.17The Company has a $10,000,000 term loan (remaining balance of $9,166,665 at September 30, 2003) which matures on April 1, 2008. The interest rate is fixed at 4.56% until maturity. ITEM
8.8 FINANCIAL STATEMENTS
Report of Independent Auditors 18 Consolidated Balance Sheets
As of September 30, 2003 and 200219-20 Consolidated Statements of Income for the
Years Ended September 30, 2003, 2002 and 200121 Consolidated Statements of Stockholders’ Equity for
the Years Ended September 30, 2003, 2002 and 200122 Consolidated Statements of Cash Flows for
the Years Ended September 30, 2003, 2002 and 200123-24 Notes to Consolidated Financial Statements 25-42 (17)
Report of Independent Auditors
................................... 19 Consolidated Balance Sheets As of September 30, 2002 and 2001 ....................... 20-21 Consolidated Statements of Income for the Years Ended September 30, 2002, 2001 and 2000 ........... 22 Consolidated Statements of Stockholders' Equity for the Years Ended September 30, 2002, 2001 and 2000 ................. 23 Consolidated Statements of Cash Flows for the Years Ended September 30, 2002, 2001 and 2000 ....... 24-25 Notes to Consolidated Financial Statements ....................... 26-43 18Report of Independent AuditorsBoard of Directors and Stockholders
Panhandle Royalty CompanyWe have audited the accompanying consolidated balance sheets of Panhandle Royalty Company (the Company) as of September 30,
20022003 and2001,2002, and the related consolidated statements of income,stockholders'stockholders’ equity, and cash flows for each of the three years in the period ended September 30,2002.2003. These financial statements are the responsibility of theCompany'sCompany’s management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the 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 consolidated financial position of Panhandle Royalty Company at September 30,
20022003 and2001,2002, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30,2002,2003, in conformity with accounting principles generally accepted in the United States.ERNSTErnst &
YOUNGYoung, LLP
Oklahoma City, Oklahoma
December10, 2002 195, 2003 (18)
Panhandle Royalty Company
Consolidated Balance Sheets
SEPTEMBER 30 2002 2001 ---------------------------------------ASSETS Current assets: Cash and cash equivalents $ 242,836 $ 98,970 Oil and gas sales receivable 2,533,249 1,566,538 Income tax receivable - 294,137 Prepaid expenses 5,709 4,552 --------------------------------------- Total current assets 2,781,794 1,964,197 Property and equipment at cost, based on successful efforts accounting: Producing oil and gas properties 58,697,095 34,737,546 Nonproducing oil and gas properties 9,754,336 6,384,332 Furniture and fixtures 360,784 287,268 --------------------------------------- 68,812,215 41,409,146 Less accumulated depreciation, depletion, and amortization 27,860,713 22,061,402 --------------------------------------- Net properties and equipment 40,951,502 19,347,744 Investment in partnerships 856,607 - Escrow deposit and deferred costs related to Wood Oil acquisition - 3,860,027 Other assets 247,157 107,716 --------------------------------------- Total assets $ 44,837,060 $ 25,279,684 =======================================(Continued
September 30 2003 2002 Current assets: Cash and cash equivalents $ 593,006 $ 242,836 Oil and gas sales receivable 3,989,877 2,533,249 Prepaid expenses and other 117,422 5,709 Total current assets 4,700,305 2,781,794 Property and equipment at cost, based on successful efforts accounting: Producing oil and gas properties 65,342,062 58,697,095 Nonproducing oil and gas properties 9,610,757 9,754,336 Furniture and fixtures 405,514 360,784 75,358,333 68,812,215 Less accumulated depreciation, depletion, and amortization 31,685,848 27,860,713 Net properties and equipment 43,672,485 40,951,502 Investment in partnerships, at equity 782,587 856,607 Other 247,157 247,157 Total assets $ 49,402,534 $ 44,837,060 (Continued on next page.)
20
SEPTEMBER 30 2002 2001 ---------------------------------------LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 653,758 $ 478,580 Accrued liabilities: Deferred compensation 321,555 378,014 Interest 66,567 - Other 133,308 63,269 Income taxes payable 10,063 - Long-term debt due within one year 3,996,000 - --------------------------------------- Total current liabilities 5,181,251 919,863 Long-term debt 14,024,000 4,050,000 Deferred income taxes 8,639,000 3,284,000 Other noncurrent liabilities 39,515 30,771 Stockholders' equity: Class A voting common stock, $.0333 par value; 6,000,000 shares authorized, 2,079,423 issued and outstanding (2,066,441 in 2001) 69,314 68,881 Capital in excess of par value 896,643 702,948 Retained earnings 15,987,337 16,223,221 --------------------------------------- Total stockholders' equity 16,953,294 16,995,050 --------------------------------------- Total liabilities and stockholders' equity $ 44,837,060 $ 25,279,684 =======================================(19)
September 30 2003 2002 Current liabilities: Accounts payable $ 552,201 $ 653,758 Accrued liabilities: Deferred compensation 519,783 321,555 Interest 40,213 66,567 Other 121,972 133,308 Income taxes payable 130,788 10,063 Long-term debt due within one year 2,000,004 3,996,000 Total current liabilities 3,364,961 5,181,251 Long-term debt 12,666,661 14,024,000 Deferred income taxes 10,315,000 8,639,000 Asset retirement obligation and other noncurrent liabilities 528,227 39,515 Stockholders’ equity: Class A voting common stock, $.0333 par value; 6,000,000 shares authorized, 2,089,101 issued and outstanding (2,079,423 in 2002) 69,637 69,314 Capital in excess of par value 1,091,886 896,643 Retained earnings 21,366,162 15,987,337 Total stockholders’ equity 22,527,685 16,953,294 Total liabilities and stockholders’ equity $ 49,402,534 $ 44,837,060 See accompanying notes.
21(20)
Panhandle Royalty Company
Consolidated Statements of Income
YEAR ENDED SEPTEMBER 30 2002 2001 2000 -----------------------------------------------------------Revenues: Oil and gas sales $ 13,080,754 $ 12,546,055 $9,091,920 Lease bonuses and rentals 41,497 17,991 82,030 Interest 36,743 47,141 17,689 Income from partnerships and other (Note 2) 432,403 184,735 86,335 ----------------------------------------------------------- 13,591,397 12,795,922 9,277,974 Costs and expenses: Lease operating expenses and production taxes 3,001,449 1,771,789 1,458,935 Exploration costs 417,971 947,046 514,739 Depreciation, depletion, and amortization 5,845,779 1,670,961 1,789,491 Provision for impairment 1,116,234 848,535 262,998 General and administrative 2,263,908 1,689,426 1,450,241 Interest expense 895,997 779 15,643 ----------------------------------------------------------- 13,541,338 6,928,536 5,492,047 ----------------------------------------------------------- Income before provision for income taxes 50,059 5,867,386 3,785,927 Provision (benefit) for income taxes (293,000) 1,600,000 925,000 ----------------------------------------------------------- Net income $ 343,059 $ 4,267,386 $2,860,927 =========================================================== Basic earnings per share $ .17 $ 2.07 $ 1.39 =========================================================== Diluted earnings per share $ .16 $ 2.05 $ 1.38 ===========================================================
Year ended September 30 2003 2002 2001 Revenues: Oil and gas sales $ 22,098,198 $ 13,080,754 $ 12,546,055 Lease bonuses and rentals 72,765 41,497 17,991 Interest 13,580 36,743 47,141 Income from partnerships and other 271,495 432,403 184,735 22,456,038 13,591,397 12,795,922 Costs and expenses: Lease operating expenses and production taxes 4,013,572 3,001,449 1,771,789 Exploration costs 469,224 417,971 947,046 Depreciation, depletion, and amortization 5,783,457 5,845,779 1,670,961 Provision for impairment 692,220 1,116,234 848,535 General and administrative 2,666,177 2,263,908 1,689,426 Interest expense 699,266 895,997 779 14,323,916 13,541,338 6,928,536 Income before provision for income taxes and cumulative effect of accounting change 8,132,122 50,059 5,867,386 Provision (benefit) for income taxes 2,217,000 (293,000 ) 1,600,000 Net income before cumulative effect of accounting change 5,915,122 343,059 4,267,386 Cumulative effect of accounting changes, net of taxes of $28,500 46,500 — — Net income $ 5,961,622 $ 343,059 $ 4,267,386 Basic earnings per common share Income before cumulative effect of accounting change $ 2.84 $ .17 $ 2.07 Cumulative effect of accounting change .02 — — Net income $ 2.86 $ .17 $ 2.07 Diluted earnings per common share Income before cumulative effect of accounting change $ 2.81 $ .16 $ 2.05 Cumulative effect of accounting change .02 — — Net income $ 2.83 $ .16 $ 2.05 See accompanying notes.
22(21)
Panhandle Royalty Company
Consolidated Statements of
Stockholders'Stockholders’ Equity
COMMON STOCK CAPITAL IN -------------------------- EXCESS OF RETAINED SHARES AMOUNT PAR VALUE EARNINGS TOTAL -----------------------------------------------------------------------Balances at September 30, 1999 2,056,990 $ 68,566 $ 587,058 $ 10,392,980 $ 11,048,604 Purchase and cancellation of common shares (3,368) (112) (70,798) - (70,910) Issuance of common shares to ESOP 6,584 219 92,020 - 92,239 Dividends declared ($.28 per share) - - - (577,046) (577,046) Net income - - - 2,860,927 2,860,927 ----------------------------------------------------------------------- Balances at September 30, 2000 2,060,206 68,673 608,280 12,676,861 13,353,814 Purchase and cancellation of common shares (146) (5) (1,855) - (1,860) Issuance of common shares to ESOP 6,381 213 96,523 - 96,736 Dividends declared ($.35 per share) - - - (721,026) (721,026) Net income - - - 4,267,386 4,267,386 ----------------------------------------------------------------------- Balances at September 30, 2001 2,066,441 68,881 702,948 16,223,221 16,995,050 Purchases and cancellation of common shares (291) (10) (4,100) (4,110) Issuance of common shares to ESOP 8,157 272 118,412 - 118,684 Issuance of common shares to directors for services 5,116 171 79,383 - 79,554 Dividends declared ($.28 per share) - - - (578,943) (578,943) Net income - - - 343,059 343,059 ----------------------------------------------------------------------- Balances at September 30, 2002 2,079,423 $ 69,314 $ 896,643 $ 15,987,337 $ 16,953,294 =======================================================================
Common Stock Capital in Excess of Retained Shares Amount Par Value Earnings Total Balances at September 30, 2001 2,066,441 $ 68,881 $ 702,948 $ 16,223,221 $ 16,995,050 Purchases and cancellation of common shares (291 ) (10 ) (4,100 ) — (4,110 ) Issuance of common shares to ESOP 8,157 272 118,412 — 118,684 Issuance of common shares to directors for services 5,116 171 79,383 — 79,554 Dividends declared ($.28 per share) — — — (578,943 ) (578,943 ) Net income — — — 343,059 343,059 Balances at September 30, 2002 2,079,423 69,314 896,643 15,987,337 16,953,294 Purchases and cancellation of common shares (54 ) (2 ) (776 ) — (778 ) Issuance of common shares to ESOP 6,642 222 152,676 — 152,898 Issuance of common shares to directors for services 3,090 103 43,343 — 43,446 Dividends declared ($.28 per share) — — — (582,797 ) (582,797 ) Net income — — — 5,961,622 5,961,622 Balances at September 30, 2003 2,089,101 $ 69,637 $ 1,091,886 $ 21,366,162 $ 22,527,685 See accompanying notes.
23(22)
Panhandle Royalty Company
Consolidated Statements of Cash Flows
YEAR ENDED SEPTEMBER 30 2002 2001 2000 ----------------------------------------------------------OPERATING ACTIVITIES Net income $ 343,059 $ 4,267,386 $ 2,860,927 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization, and impairment 6,962,013 2,519,496 2,052,489 Deferred income taxes (453,000) 1,444,000 271,000 Deferred lease bonus 8,744 30,771 - Exploration costs 417,971 947,046 514,739 Gain on sale of assets (179,037) - - Equity in earnings of partnerships (77,015) - - Common stock issued to Employee Stock Ownership Plan 118,684 96,736 92,239 Cash provided (used) by changes in assets and liabilities, net of amounts acquired in Wood Oil acquisition: Oil and gas sales receivables 191,908 389,052 (821,437) Income taxes receivable 415,810 (294,137) - Prepaid expenses 239,691 (735) 315 Accounts payable and accrued liabilities (517,696) 152,677 192,795 Income taxes payable 10,063 (249,327) 202,999 ---------------------------------------------------------- Total adjustments 7,138,136 5,035,579 2,505,139 ---------------------------------------------------------- Net cash provided by operating activities 7,481,195 9,302,965 5,366,066 INVESTING ACTIVITIES Capital expenditures, including dry hole costs (6,967,767) (9,486,994) (4,089,851) Acquisition of Wood, net of cash acquired (15,229,466) - - Distributions from partnerships 191,685 - - Investment in partnerships (90,000) - - Proceeds from sale of assets 1,371,272 - - Escrow deposit and payments related to Wood Oil acquisition - (3,860,027) - ---------------------------------------------------------- Net cash used in investing activities (20,724,276) (13,347,021) (4,089,851)
Year ended September 30 2003 2002 2001 Net income $ 5,961,622 $ 343,059 $ 4,267,386 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of accounting change (46,500 ) — — Depreciation, depletion, amortization, and impairment 6,475,677 6,962,013 2,519,496 Deferred income taxes 1,676,000 (453,000 ) 1,444,000 Deferred lease bonus 67,673 8,744 30,771 Exploration costs 469,224 417,971 947,046 Gain on sale of assets (38,378 ) (179,037 ) — Equity in earnings of partnerships (133,836 ) (77,015 ) — Common stock issued to Employee Stock Ownership Plan 152,898 118,684 96,736 Cash provided (used) by changes in assets and liabilities, net of amounts acquired in Wood Oil acquisition: Oil and gas sales receivables (1,456,628 ) 191,908 389,052 Prepaid expenses and other (111,713 ) 655,501 (294,872 ) Accounts payable and accrued liabilities 61,604 (517,696 ) 152,677 Income taxes payable 120,725 10,063 (249,327 ) Total adjustments 7,236,746 7,138,136 5,035,579 Net cash provided by operating activities 13,198,368 7,481,195 9,302,965 Capital expenditures, including dry hole costs (9,195,916 ) (6,967,767 ) (9,486,994 ) Acquisition of Wood, net of cash acquired — (15,229,466 ) — Distributions received from partnerships 252,856 191,685 — Investment in partnerships (45,000 ) (90,000 ) — Proceeds from sale of assets 76,772 1,371,272 — Escrow deposit and payments related to Wood Oil acquisition — — (3,860,027 ) Net cash used in investing activities (8,911,288 ) (20,724,276 ) (13,347,021 ) Continued on next page.
24(23)
Panhandle Royalty Company
Consolidated Statements of Cash Flows (continued)
YEAR ENDED SEPTEMBER 30 2002 2001 2000 ---------------------------------------------FINANCING ACTIVITIES Borrowings under debt agreement 18,100,000 4,050,000 500,000 Payments of loan principal (4,130,000) - (500,000) Purchase and cancellation of common shares (4,110) (1,860) (70,910) Payments of dividends (578,943) (721,026) (602,600) --------------------------------------------- Net cash provided by (used in) financing activities 13,386,947 3,327,114 (673,510) --------------------------------------------- Increase (decrease) in cash and cash equivalents 143,866 (716,942) 602,705 Cash and cash equivalents at beginning of year 98,970 815,912 213,207 --------------------------------------------- Cash and cash equivalents at end of year $ 242,836 $ 98,970 $ 815,912 ============================================= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Interest paid $ 829,430 $ 36,798 $ 15,643 Income taxes paid, net of refunds received (215,687) 699,464 451,167
Year ended September 30 2003 2002 2001 Borrowings under debt agreement $ 1,525,000 $ 18,100,000 $ 4,050,000 Payments of loan principal (4,878,335 ) (4,130,000 ) — Purchase and cancellation of common shares (778 ) (4,110 ) (1,860 ) Payments of dividends (582,797 ) (578,943 ) (721,026 ) Net cash provided by (used in) financing activities (3,936,910 ) 13,386,947 3,327,114 Increase (decrease) in cash and cash equivalents 350,170 143,866 (716,942 ) Cash and cash equivalents at beginning of year 242,836 98,970 815,912 Cash and cash equivalents at end of year $ 593,006 $ 242,836 $ 98,970 Interest paid $ 727,153 $ 829,430 $ 36,798 Income taxes paid, net of refunds received 456,338 (215,687 ) 699,464 See accompanying notes.
25(24)
Panhandle Royalty Company
Notes to Consolidated Financial Statements
September 30, 2003, 2002
2001and200020011.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION AND BASIS OF PRESENTATIONSummary of Significant Accounting PoliciesPrinciples of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of Panhandle Royalty Company and its wholly owned subsidiaries after elimination of all material intercompany transactions.
USE OF ESTIMATESUse of Estimates
The 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 reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
CASH AND CASH EQUIVALENTSCash 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 AND GAS SALES AND GAS IMBALANCESOil and Gas Sales and Gas Imbalances
The Company sells oil and natural gas to various customers, recognizing revenues as oil and gas is produced and sold. The Company uses the sales method of accounting for 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 reservoir cannot be recouped through the production of remaining reserves. At September 30,
20022003 and2001,2002, the Company had no material gas imbalances.Charges for gathering and transportation are included in lease operating expenses and production taxes.
CONCENTRATION OF CREDIT RISKConcentration of Credit Risk
Substantially all of the
Company'sCompany’s accounts receivable are due from purchasers of oil and natural gas or operators of the oil and gas properties. Oil and natural gas sales are generally unsecured. The Company has not experienced significant credit losses in prior years and is not aware of any significant uncollectible accounts at September 30,2002. 262003. (25)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) OIL AND GAS PRODUCING ACTIVITIESSummary of Significant Accounting Policies (continued)Oil and Gas Producing Activities
The Company follows the successful efforts method of accounting for oil and gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are 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 gas mineral and leasehold costs are capitalized when incurred.
DEPRECIATION, DEPLETION, AMORTIZATION, AND IMPAIRMENTDepreciation, Depletion, Amortization, and Impairment
Depreciation, depletion, and amortization of the costs of producing oil and gas properties are generally computed using the units of production method primarily on a
separate-propertyseparate property basis using proved reserves as estimated annually by an independent petroleum engineer. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years.The Company has significant royalty interests in wells for which the Company does not share in the costs associated with the wells. Estimated costs of future dismantlement, restoration and abandonment of wells in which the Company owns a working interest are not expected to differ significantly from the estimated salvage value of equipment from such wells and, accordingly, no accrual of such costs is included in the accompanying consolidated financial statements. See Recently Issued Accounting Pronouncements.Nonproducing oil and gas properties include nonproducing minerals, which have a net book value of
$7,253,206$6,930,687 at September 30,2002,2003, consisting of perpetual ownership of mineral interests in several states, including Oklahoma, Texas and New Mexico. These costs are being amortized over a thirty-three year period using the straight-line method. An ultimate determination of whether these properties contain recoverable reserves in economical quantities is expected to be made within this time frame. Impairment of nonproducing oil and gas properties is recognized based on experience and management judgment.27Panhandle Royalty Company Notes to Consolidated Financial Statements (continued) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)In accordance with the provisions of Financial Accounting Standards (SFAS) No.
121,144,Accounting for the Impairment or Disposal of Long-Lived Assetsand for Long-Lived Assets to Be Disposed Of,, 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 theassets'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 future cash flows. TheCompany'sCompany’s oil and gas properties were reviewed for indicators of impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $692,220, $1,116,234,$848,535and$262,998,$848,535, respectively, for 2003, 20022001and2000.2001. The majority of the impairment recognized in these years relates to fields comprised of a small number of properties or single wells on which the Company does not expect sufficient future net cash flow to recover its carrying cost.ENVIRONMENTAL COSTS 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, 2002, there were no such costs accrued. EARNINGS PER SHARE OF COMMON STOCK Basic earnings per share (EPS) is calculated using net income divided by the weighted average of common shares outstanding during the year. Diluted EPS is similar to basic EPS except that the weighted average common shares outstanding is increased to include the number of additional common shares that would have been outstanding if the dilutive potential common shares had been issued. The treasury stock method is used to calculate dilutive shares, which reduces the gross number of dilutive shares (see Note 5). 28(26)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) FAIR VALUES OF FINANCIAL INSTRUMENTS The carrying amounts reported in the balance sheets for cash and cash equivalents, receivables, prepaid expenses, accounts payable, and accrued liabilities approximate their fair values due to the short maturitySummary ofthese instruments. The fair value of Company's long-term debt approximates its carrying amount due to the variable interest rate on these borrowings. RECLASSIFICATIONS Certain reclassifications have been made to prior year amounts to conform with the current year presentation. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTSSignificant Accounting Policies (continued)Asset Retirement Obligations
In August 2001, the FASB issued SFAS No. 143,Accounting for Asset Retirement Obligations
(SFAS(SFAS No. 143). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method and the liability should be accreted to its face amount. The Company adopted SFAS No. 143 on October 1, 2002. The primary impact of this standard relates to oil and gas wells on which the Company has a legal obligation to plug and abandon the wells. Prior to SFAS No. 143, Company had not recorded an obligation for these plugging and abandonment costs due to its assumption that the salvage value of the surface equipment would offset the cost of dismantling the facilities and carrying out the necessary clean-up and reclamation activities. The adoption of SFAS No. 143 on October 1, 2002 resulted in a net increase to Property and Equipment and Asset Retirement Obligations of approximately$325,000$481,000 and$250,000,$406,000, respectively, as a result of the Company separately accounting for salvage values and recording the estimated fair value of its plugging and abandonment obligations on the balance sheet. The increase in expense resulting from the accretion of the asset retirement obligation and the depreciation of the additional capitalized well costsis expected to bewas substantially offset by the decrease in depreciation from theCompany'sCompany’s consideration of the estimated salvage values in the calculation.29Environmental Costs
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, 2003, there were no such costs accrued.
Earnings Per Share of Common Stock
Basic earnings per share (EPS) is calculated using net income divided by the weighted average of common shares outstanding during the year. Diluted EPS is similar to basic EPS except that the weighted average common shares outstanding is increased to include the number of additional common shares that would have been outstanding if the dilutive potential common shares had been issued. The treasury stock method is used to calculate dilutive shares, which reduces the gross number of dilutive shares (see Note 5).
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) In October 2001,Summary of Significant Accounting Policies (continued)Stock-based Compensation
The Company applies APB Opinion No. 25 in accounting for its Deferred Compensation Plan for Outside Directors. Under APB No. 25, compensation cost is recognized for changes in the
FASB issued SFAS No. 144, Accountingfair value of the stock credited to each director’s account at the fair market value of the stock at the date of grant. The shares are then adjusted for changes in theImpairment or Disposalshares market value subsequent to the date ofLong-Lived Assets (SFAS No. 144)grant until the conversion date (see Note 7).SFAS No. 144 addresses financial accountingFair Values of Financial Instruments
The carrying amounts reported in the balance sheets for cash and
reporting forcash equivalents, receivables, prepaid expenses, accounts payable, and accrued liabilities approximate their fair values due to theimpairmentshort maturity oflong-lived assets and for long-lived assetsthese instruments. The fair value of Company’s long-term debt approximates its carrying amount due tobe disposed of. It supercedes, with exceptions, SFAS No. 121. SFAS No. 144 was adopted bytheCompany on October 1, 2002. The adoption of SFAS No. 144 had no material impactinterest rate on theCompany's financial position or results of operations.Company’s term-loan being a fixed rate which approximated market rates at September 30, 2003, the remaining borrowings bear interest at a variable rate.Recently Issued Accounting Pronouncements
In June 2002, FASB issued SFAS 146,Accounting for Costs Associated with Exit or Disposal
Activities.Activities. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3,Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit anActivity.Activity. The pronouncement is effective for exit or disposal activities initiated after December 31, 2002.Management does not believe that theThe adoption of SFAS 146will have anyhad no material impact onitsthe Company’s financial position or results of operations and is currently expected to in the near term.In April 2003, the FASB issued FAS No. 149, Amendment of Statement 133 onDerivative Instruments and Hedging Activities. This Statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities. This statement is effective for contracts entered into or modified after June 30, 2003. Adoption of this Statement had no impact on the financial position or results of operation of the Company and is currently not expected to in the near term.
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
In May 2003, the FASB issued SFAS 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS 150 establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Under SFAS 150, mandatorily redeemable financial instruments, obligations to repurchase the issuer’s shares by transferring assets and certain obligations to issue a variable number of shares to settle that obligation must be classified as liabilities on the balance sheet and initially recorded at fair value. SFAS 150 is effective for the Company for financial instruments entered into or modified after May 31, 2003, and on July 1, 2003 for most previously existing financial instruments. In November 2003, the FASB voted to defer indefinitely the effective date for certain mandatorily redeemable non-controlling interests (MRNI) associated with finite-lived subsidiaries. For all other MRNIs, the effective date was deferred to November 5, 2003. The adoption of SFAS 150 did not impact our financial position, results of operations or net cash flows as the Company currently does not use any of the financial instruments subject to this statement.
In November 2002, the FASB issued FASB Interpretation (FIN) 45,Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.FIN 45 clarifies the requirements of SFAS 5,Accounting For Obligations, relating to a guarantor’s accounting for, and disclosure of the issuance of certain types of guarantees. The adoption of FIN 45 did not impact the Company’s financial position, results of operations or net cash flows as the Company currently does not have any guarantees.
In January 2003, the FASB issued FIN 46,Consolidation of Variable Interest Entities,An Interpretation of Accounting Research Bulletin No. 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities (VIE)) and how to determine when and which business enterprises should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. FIN 46 applies immediately to VIEs created after January 31, 2003 or to VIEs obtained after that date. For variable interests held in VIEs acquired prior to February 1, 2003, FIN 46 was originally effective July 1, 2003. However, in October 2003, the FASB deferred the effective date of FIN 46 for VIEs created prior to February 1, 2003 to the first reporting period after December 15, 2003. The adoption of this interpretation is not
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Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
1. Summary of Significant Accounting Policies (continued)
anticipated to have a material impact on the Company’s financial position, results of operations or net cash flows because the Company currently is not a primary beneficiary of a VIE.
2.
ACQUISITION OF WOOD OIL COMPANYAcquisition of Wood Oil CompanyOn October 1, 2001, the Company acquired 100% of the outstanding common stock of Wood Oil Company (Wood). The acquisition was made pursuant to an Agreement and Plan of Merger among the Company, PHC, Inc. and Wood Oil Company, dated August 9, 2001. Wood merged with
Panhandle'sPanhandle’s wholly owned subsidiary PHC, Inc., on October 1, 2001, with Wood being the surviving Company. Prior to the acquisition, Wood was a privately held company engaged in oil and gas exploration and production and fee mineral ownership and owned interests in certain oil and gas and real estate partnerships and owned an office building in Tulsa, Oklahoma. Subsequent to the acquisition, Wood has continued to operate as a subsidiary of Panhandle and personnel were moved to Oklahoma City in early 2002. Wood and its shareholders were unrelated parties to Panhandle.30Panhandle Royalty Company Notes to Consolidated Financial Statements (continued) 2. ACQUISITION OF WOOD OIL COMPANY (CONTINUED)The
Company'sCompany’s decision to acquire Wood was the result of desired growth in theCompany'sCompany’s asset base of producing oil and gas reserves and fee mineral acreage.Wood'sWood’s oil and gas activity, fee minerals and operating philosophy, in general, had been very similar to theCompany's. Wood'sCompany’s.Wood’s mineral acreage ownership and leasehold position as well as its producing oil and gas properties are located in the same general areas as the
Company's.Company’s. In several cases, both companies owned interests in existing producing wells and several developing fields. The Company intends to actively pursue drilling opportunities onWood'sWood’s properties.Funding for the acquisition was obtained from Banc First of Oklahoma City, Oklahoma in the form of a $20 million five-year term loan. Three million of
Wood'sWood’s cash was used to reducePanhandle'sPanhandle’s debt on the date of closing.(30)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
2. Acquisition of Wood Oil Company (continued)
The operations of Wood, since October 1, 2001, are included in the accompanying consolidated financial statements.
The following table sets forth the allocation of the purchase price to the assets and liabilities acquired:
Cash $ 3,759,000 Other current assets 1,260,000 Land and buildings held for sale 750,000 Oil and gas properties - proved 17,550,000 Minerals: Producing 925,000 Nonproducing 3,491,000 Other property and equipment 43,000 Investments in partnerships and other assets 1,731,000 -------------- Total assets acquired 29,509,000 Current liabilities (853,000) Deferred income taxes (5,808,000) -------------- Total liabilities assumed (6,661,000) -------------- Net assets acquired $22,848,000 ==============31Panhandle Royalty Company Notes to Consolidated Financial Statements (continued) 2. ACQUISITIONS (CONTINUED)
Cash $ 3,759,000 Other current assets 1,260,000 Land and buildings held for sale 750,000 Oil and gas properties – proved 17,550,000 Minerals: Producing 925,000 Nonproducing 3,491,000 Other property and equipment 43,000 Investments in partnerships and other assets 1,731,000 Total assets acquired 29,509,000 Current liabilities (853,000 ) Deferred income taxes (5,808,000 ) Total liabilities assumed (6,661,000 ) Net assets acquired $ 22,848,000 In April 2002, the Company sold the land and building and its interest in two partnerships resulting in net proceeds of approximately $1.4 million of which $800,000 were used to pay down long term debt. Other revenues in the accompanying consolidated income statement include a gain of $56,487 on the sale of the building and a gain of $122,550 on the sale of the two partnerships.
The following unaudited proforma results of operations give effect to the acquisition as if consummated on October 1, 2000. The data reflects adjustments of the historical Wood results for depreciation and amortization of the property and equipment acquired, adjustments of expenses resulting from contractual requirements of the acquisition agreement, incremental interest expense relating to bank borrowing used to finance the purchase and income taxes. Total revenues for 2001 include non-recurring gains on asset sales of $2.1 million. The pro forma adjustments are based upon available information and assumptions that management of the Company believes are reasonable. The pro forma results of operations data does
(31)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
2. Acquisition of Wood Oil Company (continued)
not purport to represent the results of operations that would have occurred had such transaction been consummated on October 1, 2000 or the
Company'sCompany’s results of operation for any future date or period.
YEAR ENDED SEPTEMBER 30, 2001 -----------------Total revenues $25,234,054 Net income $ 8,927,780 Diluted earnings per share $ 4.2732Panhandle Royalty Company Notes to Consolidated Financial Statements (continued)
Year ended September 30, 2001 Total revenues $ 25,234,054 Net income $ 8,927,780 Diluted earnings per share $ 4.27 3.
INCOME TAXESIncome TaxesThe
Company'sCompany’s provision for income taxes is detailed as follows:
2002 2001 2000 -----------------------------------------Current: Federal $ 150,000 $ 160,000 $647,000 State 10,000 (4,000) 7,000 ------------------------------------------ 160,000 156,000 654,000 Deferred: Federal (390,000) 1,232,000 244,000 State (63,000) 212,000 27,000 ------------------------------------------ (453,000) 1,444,000 271,000 ------------------------------------------ $(293,000) $1,600,000 $925,000 ==========================================
2003 2002 2001 Current: Federal $ 521,000 $ 150,000 $ 160,000 State 20,000 10,000 (4,000 ) 541,000 160,000 156,000 Deferred: Federal 1,607,000 (390,000 ) 1,232,000 State 69,000 (63,000 ) 212,000 1,676,000 (453,000 ) 1,444,000 $ 2,217,000 $ (293,000 ) $ 1,600,000 The difference between the provision for income taxes and the amount which would result from the application of the federal statutory rate to income before provision for income taxes is analyzed below:
2002 2001 2000 -----------------------------------------Provision for income taxes at statutory rate $ 17,521 $2,053,587 $1,325,074 Percentage depletion (201,600) (559,668) (368,687) Tight-sands gas credits (77,404) (47,114) (59,359) State income taxes, net of federal benefit (34,419) 141,099 22,125 Other 2,902 12,096 5,847 ----------------------------------------- $(293,000) $1,600,000 $ 925,000 =========================================33
2003 2002 2001 Provision for income taxes at statutory rate $ 2,762,324 $ 17,521 $ 2,053,587 Percentage depletion (653,947 ) (201,600 ) (559,668 ) Tight-sands gas credits (20,000 ) (77,404 ) (47,114 ) State income taxes, net of federal benefit 57,850 (34,419 ) 141,099 Other 70,773 2,902 12,096 $ 2,217,000 $ (293,000 ) $ 1,600,000 (32)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
3.
INCOME TAXES (CONTINUED)Income Taxes (continued)Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax bases of assets and liabilities, consist of the following:
2002 2001 -------------------------------Deferred tax liabilities: Financial bases in excess of tax bases, including intangible drilling costs capitalized for financial purposes and expensed for tax purposes $11,210,000 $4,029,000 Deferred tax assets: Percentage depletion and alternative minimum tax credit carryforwards 1,950,000 308,000 Financial charges which are deferred for tax purposes 621,000 437,000 ------------------------------- 2,571,000 745,000 ------------------------------- Net deferred tax liabilities $ 8,639,000 $3,284,000 ===============================
2003 2002 Deferred tax liabilities: Financial bases in excess of tax bases, including intangible drilling costs capitalized for financial purposes and expensed for tax purposes $ 11,744,000 $ 11,210,000 Deferred tax assets: Percentage depletion and alternative minimum tax credit carry forwards 991,000 1,950,000 Financial charges which are deferred for tax purposes 438,000 621,000 1,429,000 2,571,000 Net deferred tax liabilities $ 10,315,000 $ 8,639,000 4.
LONG-TERM DEBTLong-Term DebtLong-term debt consisted of the following at September 30:
2002 2001 -------------------------------Revolving line of credit $ 1,350,000 $4,050,000 Term loan 16,670,000 - ------------------------------- 18,020,000 4,050,000 Current maturities of long-term debt 3,996,000 - ------------------------------- $14,024,000 $4,050,000 ===============================34
2003 2002 Revolving line of credit $ 5,500,000 $ 1,350,000 Term loan 9,166,665 16,670,000 14,666,665 18,020,000 Current maturities of long-term debt 2,000,004 3,996,000 $ 12,666,661 $ 14,024,000 On March 25, 2003, the Company amended its Loan Agreement with BancFirst of Oklahoma City, Oklahoma. The Agreement consists of a term loan in the amount of $10,000,000 and a revolving loan in the amount of $15,000,000, which is subject to a semi-annual borrowing base determination. The current borrowing base under the
(33)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
4.
LONG-TERM DEBT (CONTINUED) In October 2001, the Company entered into an amended and restated loan agreement with BancFirst of Oklahoma City, Oklahoma that provided a $20 million five-yearLong-Term Debt (continued)Agreement is $22,500,000. The term loan matures on April 1, 2008, and
extendedthematurity date of the Company's existing $5 millionrevolvingline of credit.loan matures on April 1, 2005. Monthlyprincipalpayments on the term loanwhich began in December 2001,are$333,000. Outstanding borrowings$166,667, plus accrued interest, beginning on May 1, 2003. Borrowings under the revolvingline of creditloan arepayable in fulldue at maturity. Interest onDecember 31, 2003, unless extended. Interestthe term loan ispayable monthly under both instruments and is based onfixed at 4.56% until maturity. The revolving loan bears interest at the national prime rate minus.25% (aggregate of 4.5%-3/4% (3.25% at September 30,2002)2003) or LIBOR (for one, three or six month periods), plus 1.80%.Borrowings under these agreements are secured by certainThe Company, at September 30, 2003, has elected a six month LIBOR rate (aggregate ofthe Company's oil and gas properties.2.98%).The total outstanding borrowings under both the term loan and the revolving line of credit may not exceed the borrowing base which is
$25$22.5 million as of September 30,2002.2003. Subsequent 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 gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit theCompany'sCompany’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2003 the Company was in compliance with the covenants. Certain of the Company’s oil and gas properties secure the debt.The amount of required principal payments for the next five years as of September 30,
2002,2003, are as follows:2003-$3,996,000, 2004-$5,346,000, 2005-$3,996,000, 2006-$3,996,000,2004 – $2,000,004, 2005 – $7,500,004, 2006 - - $2,000,004, 2007 – $2,000,004 and2007-$686,000. 352008 – $1,166,649. (34)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
5.
EARNINGS PER SHAREEarnings Per ShareThe following table sets forth the computation of basic and diluted earnings per share. The
Company'sCompany’s diluted earnings per share calculation takes into account certain shares that may be issued under the Non-EmployeeDirectors'Directors’ Deferred Compensation Plan (see Note 7).
YEAR ENDED SEPTEMBER 30, 2002 2001 2000 -------------------------------------Numerator for primary and diluted earnings per share: Net income $ 343,059 $4,267,386 $2,860,927 ===================================== Denominator: For basic earnings per share-- weighted average shares 2,067,872 2,060,109 2,055,470 Effect of potential diluted shares: Directors' deferred compensation shares 22,100 24,935 21,960 ------------------------------------- Denominator for diluted earnings per share--adjusted weighted average shares and potential shares 2,089,972 2,085,044 2,077,430 ===================================== Basic earnings per share $.17 $2.07 $1.39 ===================================== Diluted earnings per share $.16 $2.05 $1.38 =====================================36
Year ended September 30, 2003 2002 2001 Numerator for primary and diluted earnings per share: Net income $ 5,961,622 $ 343,059 $ 4,267,386 Denominator: For basic earnings per share—weighted average shares 2,081,372 2,067,872 2,060,109 Effect of potential diluted shares: Directors’ deferred compensation shares 22,341 22,100 24,935 Denominator for diluted earnings per share—adjusted weighted average shares and potential shares 2,103,713 2,089,972 2,085,044 (35)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
6.
EMPLOYEE STOCK OWNERSHIP PLANEmployee Stock Ownership PlanThe Company has an employee stock ownership plan that covers substantially all employees and is established to provide such employees with a retirement benefit. These benefits become fully vested after three years of employment. Contributions to the plan are at the discretion of the Board of Directors and can be made in cash (none in 2003, 2002
2001or2000)2001) or theCompany'sCompany’s common stock. For contributions of common stock, the Company records as expense, the fair market value of the stock at the time of contribution. The122,747129,904 shares of theCompany'sCompany’s common stock held by the plan as of September 30,2002,2003, 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:
YEAR SHARES AMOUNT --------------------------------------------------------2002 8,157 $ 118,684 2001 6,381 $ 96,736 2000 6,584 $ 92,239
Year Shares Amount 2003 6,911 $ 156,978 2002 8,157 $ 118,684 2001 6,381 $ 96,736 7.
DEFERRED COMPENSATION PLAN FOR DIRECTORSDeferred Compensation Plan for DirectorsEffective November 1, 1994, the Company formed the Panhandle Royalty Company Deferred Compensation Plan for Non-Employee Directors (the Plan). The Plan provides that each eligible director can individually elect to receive shares of Company stock rather than cash for board meeting fees and board committee meeting fees. These shares are unissued and vest at the date of grant. The shares are credited to each
director'sdirector’s deferred fee account at the fair market value of the stock at the date of grant and are adjusted for changes in market value subsequent thereto. Upon retirement, termination or death of the director, or upon change in control of the Company, the shares accrued under the Plan will be either issued to the director or may be converted to cash, at thedirector'sdirector’s discretion, for the fair market value of the shares on the conversion date as defined by the Plan. As of September 30,2002, 22,1002003, 22,908 shares(24,935(22,100 shares at September 30,2001)2002) are included in the Plan. The Company has accrued$321,555$519,783 at September 30,20022003 ($378,014321,555 at September 30,2001)2002) in connection with the Plan ($23,095,241,673, $23,095, and $70,570and $174,717was charged to the results of operations for the years ended September 30, 2003, 20022001and2000,2001, respectively, and is included in general and administrative expense in the accompanying income statement).37(36)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
8.
INFORMATION ON OIL AND GAS PRODUCING ACTIVITIESInformation on Oil and Gas Producing ActivitiesAll oil and gas producing activities of the Company are conducted within the United States (principally
Oklahoma and New Mexico)in Oklahoma) and represent substantially all of the business activities of the Company.During 2003, 2002 and 2001
and 2000approximately 14%, 17%,23%and21%23%, respectively, of theCompany'sCompany’s total revenues were derived from gas sales to ONEOK, Inc. The Company also has interests in a field of properties, the production on which accounted for approximately 9%, 12%,15%and 15% of theCompany'sCompany’s revenues in 2003, 2002 and 2001,and 2000,respectively.AGGREGATE CAPITALIZED COSTSAggregate Capitalized Costs
The aggregate amount of capitalized costs of oil and gas properties and related accumulated depreciation, depletion, and amortization as of September 30 is as follows:
2002 2001 ----------------------------Producing properties $ 58,697,095 $ 34,737,546 Nonproducing properties 9,754,336 6,384,332 ---------------------------- 68,451,431 41,121,878 Accumulated depreciation, depletion and amortization (27,583,242) (21,813,974) ---------------------------- Net capitalized costs $ 40,868,189 $ 19,307,904 ============================COSTS INCURRED
2003 2002 Producing properties $ 65,342,062 $ 58,697,095 Nonproducing properties 9,610,757 9,754,336 74,952,819 68,451,431 Accumulated depreciation, depletion and amortization (31,386,538 ) (27,583,242 ) Net capitalized costs $ 43,566,281 $ 40,868,189 Costs Incurred
During the reporting period, the Company incurred the following costs in oil and gas producing activities:
2003 2002 2001 Property acquisition costs (A) $ 127,058 $ 219,306 $ 194,645 Exploration costs 1,412,653 1,080,951 3,839,009 Development costs 7,818,988 5,637,430 5,447,423 $ 9,358,699 $ 6,937,687 $ 9,481,077
(A) Excludes Wood Oil acquisition in 2002 2001 2000 -----------------------------------------Property acquisition costs (A) $ 219,306 $ 194,645 $ 528,691 Exploration costs 1,080,951 3,839,009 1,776,773 Development costs 5,637,430 5,447,423 1,765,401 ----------------------------------------- $6,937,687 $9,481,077 $4,070,865 =========================================as set forth in Note 2, the cost of which, net of cash acquired, was $15,229,466.(A) Excludes Wood Oil acquisition in 2002 as set forth in Note 2, the cost of which, net of cash acquired, was $15,229,466. 38(37)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
9.
SUPPLEMENTARY INFORMATION ON OIL AND GAS RESERVES (UNAUDITED)Supplementary Information on Oil and Gas Reserves (Unaudited)The following unaudited information regarding the
Company'sCompany’s oil and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission (SEC) and SFAS No. 69,Disclosures About Oil and Gas ProducingActivities.Activities.Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Because the
Company'sCompany’s nonproducing mineral and leasehold interests consist of various small interests in numerous tracts located primarily in Oklahoma, New Mexico, and Texas, it is not economically feasible for the Company to provide estimates of all proved undeveloped reserves. The Company directs its independent petroleum engineering firm to include proved undeveloped reserves in certain areas of Oklahoma and New Mexico in the scope of properties which are evaluated for the Company.The
Company'sCompany’s net proved (including certain undeveloped reserves described above) oil and gas reserves, all of which are located in the United States, as of September 30, 2003, 20022001,and2000,2001, have been estimated by Campbell & Associates, Inc., an independent petroleum engineering firm. 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, 2003, 20022001,and2000.2001. 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.39(38)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
9.
SUPPLEMENTARY INFORMATION ON OIL AND GAS RESERVES (UNAUDITED) (CONTINUED) ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVESSupplementary Information on Oil and Gas Reserves (Unaudited) (continued)Estimated Quantities of Proved Oil and Gas Reserves
Net quantities of proved, developed, and undeveloped oil and gas reserves are summarized as follows:
Proved Reserves Oil Gas (Mbarrels) (Mmcf) September 30, 2000 660 14,389 Revisions of previous estimates (47 ) (2,178 ) Extensions and discoveries 132 7,685 Production (69 ) (2,208 ) September 30, 2001 676 17,688 Revisions of previous estimates (38 ) 745 Purchases of reserves in place 487 8,519 Extensions and discoveries 123 5,061 Production (133 ) (3,897 ) September 30, 2002 1,115 28,116 Revisions of previous estimates (1) (289 ) (1,953 ) Extensions and discoveries 123 6,033 Production (113 ) (3,926 ) September 30, 2003 836 28,270
PROVED RESERVES ------------------------ OIL GAS (MBARRELS) (MMCF) ------------------------September 30, 1999 721 13,115(1) Revisions of previous estimates (1) (81) 396 Purchasesoil reserves and some associated gas reserves were principally a result of changes in reserves associated with properties inplace 6 147 Extensionsthe Dagger Draw Field of New Mexico, which will be converted to a waterflood in 2004. Gas reserve revisions resulted from properties which were drilled in the prior year anddiscoveries 81 3,186 Production (67) (2,455) ------------------------ September 30, 2000 660 14,389 Revisions of previous estimates (1) (47) (2,178) Extensions and discoveries 132 7,685 Production (69) (2,208) ------------------------ September 30, 2001 676 17,688 Revisions of previous estimates (38) 745 Purchases of reservesnow have actual performance to guide the projections, rather than the limited data available inplace 487 9,712 Extensions and discoveries 123 5,061 Production (133) (3,897) ------------------------ September 30, 2002 1,115 29,309 ========================the first few months a property comes on production.(1) Oil and gas revisions in 2001 are primarily related to those reserves that were uneconomical at the lower prices that existed at September 30, 2001. Gas revisions in 2000 are primarily related to those reserves that were economically recoverable at the higher prices that existed at September 30, 2000, which were not economically recoverable at prices existing at September 30, 1999. In 2000 and 1999, oil reserves were also revised downward due to a decline in production of certain New Mexico properties after being shut-in for several months in 1999 due to depressed oil prices. 40(39)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
9.
SUPPLEMENTARY INFORMATION ON OIL AND GAS RESERVES (UNAUDITED) (CONTINUED)
PROVED DEVELOPED RESERVES PROVED UNDEVELOPED RESERVES ------------------------- --------------------------- OIL GAS OIL GAS (MBARRELS) (MMCF) (MBARRELS) (MMCF) -----------------------------------------------------------September 30, 1999 433 11,519 288 1,596 =========================================================== September 30, 2000 409 11,585 251 2,804 =========================================================== September 30, 2001 413 13,236 263 4,452 =========================================================== September 30, 2002 821 24,090 294 5,220 ===========================================================STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWSSupplementary Information on Oil and Gas Reserves (Unaudited) (continued)
Proved Developed Reserves Proved Undeveloped Reserves Oil Gas Oil Gas (Mbarrels) (Mmcf) (Mbarrels) (Mmcf) September 30, 2000 409 11,585 251 2,804 September 30, 2001 413 13,236 263 4,452 September 30, 2002 821 22,896 294 5,220 September 30, 2003 703 23,600 133 4,670 The above reserve numbers are net of approximately 1.2 mmcf of CO2 gas reserves owned by Wood Oil Company.
Standardized Measure of Discounted Future Net Cash Flows
Estimates of future cash flows from proved oil and gas reserves, based on current prices and costs, as of September 30 are shown in the following table. Estimated income taxes are calculated by (i) applying the appropriate year-end tax rates to the estimated future pretax net cash flows less depreciation of the tax basis of properties and statutory depletion allowances and (ii) reducing the amount in (i) for estimated tax credits to be realized in the future for gas produced from
"tight-sands."
2002 2001 2000 --------------------------------------------Future cash inflows $123,668,010 $48,294,240 $78,668,350 Future production costs 25,022,170 9,355,230 12,308,320 Future development costs 3,991,185 2,999,402 1,273,629 -------------------------------------------- Future net cash inflows before future 94,654,655 35,939,608 65,086,401 income tax expenses Future income tax expense 25,831,291 9,381,868 18,332,743 -------------------------------------------- Future net cash flows 68,823,364 26,557,740 46,753,658 10% annual discount 24,878,417 8,927,795 15,892,344 -------------------------------------------- Standardized measure of discounted future net cash flows $ 43,944,947 $17,629,945 $30,861,314 ============================================41“tight-sands” through December 31, 2002.
2003 2002 2001 Future cash inflows $ 148,633,837 $ 123,668,010 $ 48,294,240 Future production costs 29,036,188 25,022,170 9,355,230 Future development costs 3,856,341 3,991,185 2,999,402 Future net cash inflows before future income tax expenses 115,741,308 94,654,655 35,939,608 Future income tax expense 31,736,989 25,831,291 9,381,868 Future net cash flows 84,004,319 68,823,364 26,557,740 10% annual discount 30,034,435 24,878,417 8,927,795 Standardized measure of discounted future net cash flows $ 53,969,884 $ 43,944,947 $ 17,629,945 (40)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
9.
SUPPLEMENTARY INFORMATION ON OIL AND GAS RESERVES (UNAUDITED) (CONTINUED)Supplementary Information on Oil and Gas Reserves (Unaudited) (continued)Changes in the standardized measure of discounted future net cash flows are as follows:
2002 2001 2000 ------------------------------------------------Beginning of year $ 17,629,945 $ 30,861,314 $ 20,071,898 Changes resulting from: Sales of oil and gas, net of production costs (10,079,305) (10,774,266) (7,632,985) Net change in sales prices and production costs 15,794,503 (17,851,098) 11,642,854 Net change in future development costs (665,685) (1,154,469) (60,124) Extensions and discoveries 10,313,163 10,190,264 8,886,844 Revisions of quantity estimates 885,028 (2,981,154) (221,761) Purchases of reserves-in-place 19,370,609 - 438,663 Accretion of discount 2,412,266 4,295,702 2,770,591 Net change in income taxes (10,933,161) 6,185,986 (4,807,558) Change in timing and other, net (782,416) (1,142,334) (227,108) ------------------------------------------------ Net change 26,315,002 (13,231,369) 10,789,416 ------------------------------------------------ End of year $ 43,944,947 $ 17,629,945 $ 30,861,314 ================================================
2003 2002 2001 Beginning of year $ 43,944,947 $ 17,629,945 $ 30,861,314 Changes resulting from: Sales of oil and gas, net of production costs (18,084,626 ) (10,079,305 ) (10,774,266 ) Net change in sales prices and production costs 20,300,852 15,794,503 (17,851,098 ) Net change in future development costs 87,405 (665,685 ) (1,154,469 ) Extensions and discoveries 15,315,189 10,313,163 10,190,264 Revisions of quantity estimates (8,291,358 ) 885,028 (2,981,154 ) Purchases of reserves-in-place – 19,370,609 – Accretion of discount 6,135,420 2,412,266 4,295,702 Net change in income taxes (4,134,614 ) (10,933,161 ) 6,185,986 Change in timing and other, net (1,303,331 ) (782,416 ) (1,142,334 ) Net change 10,024,937 26,315,002 (13,231,369 ) End of year $ 53,969,884 $ 43,944,947 $ 17,629,945 10.
QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)Quarterly Results of Operations (Unaudited)The following is a summary of the
Company'sCompany’s unaudited quarterly results of operations.
FISCAL 2002 --------------------------------------------------------------- QUARTER ENDED --------------------------------------------------------------- DECEMBER 31 MARCH 31 JUNE 30 SEPTEMBER 30 ---------------------------------------------------------------Revenues $ 3,330,561 $ 2,745,824 $3,792,994 $ 3,722,018 Income (loss) before provision for income taxes (102,237) (397,025) 623,684 (74,363) Net income (loss) (A) (76,856) (287,123) 453,684 253,354 Basic earnings (loss) per share $ (.04) (.14) $ .22 $ .13 Diluted earnings (loss) per share $ (.04) $ (.14) $ .22 $ .1242
Fiscal 2003 Quarter Ended December 31 March 31 June 30 September 30 Revenues $ 4,463,748 $ 6,980,939 $ 5,662,139 $ 5,349,212 Income before provision for income taxes and cumulative effect of accounting change 829,981 3,323,674 2,193,583 1,777,244 Income before cumulative effect of accounting change 604,981 2,320,674 1,538,583 1,443,244 Net income 651,481 2,320,674 1,538,583 1,450,884 Basic earnings per share $ .31 $ 1.12 $ .74 $ .69 Diluted earnings per share $ .31 $ 1.10 $ .73 $ .69 (41)
Panhandle Royalty Company
Notes to Consolidated Financial Statements (continued)
10.
QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) (CONTINUED)Quarterly Results of Operations (Unaudited) (continued)
Fiscal 2002 Quarter Ended December 31 March 31 June 30 September 30 Revenues $ 3,330,561 $ 2,745,824 $ 3,792,994 $ 3,722,018 Income (loss) before provision for income taxes (102,237 ) (397,025 ) 623,684 (74,363 ) Net income (loss) (A) (76,856 ) (287,123 ) 453,684 253,354 Basic earnings (loss) per share $ (.04 ) $ (.14 ) $ .22 $ .13 Diluted earnings (loss) per share $ (.04 ) $ (.14 ) $ .22 $ .12
FISCAL 2001 ----------------------------------------------------------- QUARTER ENDED ----------------------------------------------------------- DECEMBER 31 MARCH 31 JUNE(A) The quarter ended September 30, SEPTEMBER 30 -----------------------------------------------------------Revenues $3,474,221 $3,940,975 $2,918,603 $2,462,123 Income before2002, reflects a change in estimate associated with the Company’s income tax provisionfor income taxes 1,561,911 2,374,071 1,367,935 563,469 Net income (A) 1,386,310 1,690,071 1,027,935 163,070 Basic earnings per share $ .67 $ .82 $ .50 $ .08 Diluted earnings per share $ .67 $ .82 $ .49 $ .08resulting from the determination of actual percentage depletion and tight sands gas credits available to reduce the Company’s taxable income.(A) The quarters ended September 30, 2002 and 2001, reflect a change in estimate associated with the Company's income tax provision resulting from the determination of actual percentage depletion and tight sands gas credits available to reduce the Company's taxable income. 43(42)
ITEM
9.9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREN O N E
PART IIIITEM 9 A CONTROLS AND PROCEDURES
Panhandle Royalty Company management, under the supervision of and with the participation of the Chief Executive Officer and Chief Financial Officer have conducted an evaluation of the effectiveness of disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in insuring that all material information required to be filed in this annual report has been made known to them in a timely fashion. There have been no significant changes in our internal controls or in factors that could significantly affect internal controls, subsequent to the date the Chief Executive Officer and Chief Financial Officer completed their evaluation.
In accordance with
paragraph (3) of generalGeneral Instruction G (3) to Form 10-K, Part III, Items10.-13. Of10.-14. of this Report are omitted because the Company will file with the Securities and Exchange Commission not later than 120 days after the end of the fiscal year ended September 30,2002,2003, a definitive proxy statement pursuant to Regulation 14A involving the election of directors, which proxy statement is incorporated herein by reference.PART
IVIIIITEM
14. CONTROLS AND PROCEDURES Within the 90 days prior to the filing date of this report, an evaluation was carried out under the supervision and with the participation of the Company's management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to the Exchange Act Rule 13a-14. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective in timely alerting them to material information relating to the Company (including its consolidated subsidiary) required to be included in the Company's periodic SEC filings. There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation. ITEM 15.15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K(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 and to Form 10-QSB dated March 31, 1999).
(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 and to Form 10-QSB dated March 31, 1999). By-Laws as amended (Incorporated by reference to Form 8-K dated October 31, 1994) (4) Instruments defining the rights of security holders (Incorporated by reference to Certificate of Incorporation and By-Laws listed above) (10) Amendment to Loan Agreement (10) Agreement indemnifying directors and officers (Incorporated by reference to Form 10-K dated September 30, 1989) (21) Subsidiaries of the Registrant (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 REPORTS ON FORM 8-K
Form 8-K dated
October 31, 1994) (4) Instruments definingAugust 13, 2003, Regulation FD disclosure of Company’s earnings release for therightsthird quarter ofsecurity holders (Incorporated by reference to Certificate of Incorporation and By-Laws listed above) (10) Agreement indemnifying directors and officers (Incorporated by reference to Form 10-K dated September 30, 1989) (21) Subsidiaries of the Registrant (99.1) Certification of Chief Executive Officer (99.2) Certification of Chief Financial Officer REPORTS ON FORM 8-K No reports on Form 8-K were filed during the quarter ended September 30, 2002. 44fiscal 2003. (43)
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PANHANDLE ROYALTY COMPANY By: /s/ H W Peace II ------------------------------ H W Peace II, Chief Executive Officer, President, Director Date: December 18, 2002 -------------------
PANHANDLE ROYALTY COMPANY By: /s/ H W Peace II H W Peace II, Chief Executive Officer, President, Director (Principal Executive Officer) Date: December 18, 2002 In accordance with the Exchange Act, 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/ Jerry L. Smith /s/ E. Chris Kauffman - --------------------------------- ---------------------------------- Jerry L. Smith, Chairman of Board E. Chris Kauffman, Director Date December 18, 2002 Date December 18, 2002 ---------------------------- ---------------------------- /s/ Robert A. Reece /s/ Michael A. Cawley - --------------------------------- ---------------------------------- Robert A. Reece, Director Michael A. Cawley, Director Date December 18, 2002 Date December 18, 2002 ---------------------------- ---------------------------- /s/ H. Grant Swartzwelder /s/ Michael C. Coffman - --------------------------------- ---------------------------------- H. Grant Swartzwelder, Director Michael C. Coffman, Vice President Treasurer and Secretary Date December 18, 2002 (Principal Financial ---------------------------- and Accounting Officer) Date December 18, 2002 45CERTIFICATION I, HW Peace II, certify that: 1. I have reviewed this annual report on Form 10-K; 2. Based on my knowledge, this annual 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 annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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-14 and 15d-14) for the registrant and we have: a). designed such disclosure controls and procedures 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 annual report is being prepared; b). evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c). presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a). all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b). any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regards to significant deficiencies and material weaknesses. Date: December 18, 2002 /s/ HW Peace II --------------- HW Peace II Chief Executive Officer 46CERTIFICATION I, Michael C. Coffman, certify that: 1. I have reviewed this annual report on Form 10-K; 2. Based on my knowledge, this annual 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 annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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-14 and 15d-14) for the registrant and we have: a). designed such disclosure controls and procedures 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 annual report is being prepared; b). evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c). presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a). all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b). any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regards to significant deficiencies and material weaknesses. Date: December 18, 2002 /s/ Michael C. Coffman ---------------------- Michael C. Coffman Chief Financial Officer 47Part III Index to Exhibits Exhibit No. Description (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 and to Form 10-QSB dated March 31, 1999). By-Laws as amended (Incorporated by reference to Form 8-K dated October 31, 1994) (4) Instruments defining the rights of security holders (Incorporated by reference to Certificate of Incorporation and By-Laws listed above) (10) Agreement indemnifying directors and officers (Incorporated by reference to Form 10-K dated September 30, 1989) (21) Subsidiaries of the Registrant (99.1) Certification of Chief Executive Officer (99.2) Certification of Chief Financial Officer 48
| /s/ Jerry L. Smith | /s/ E. Chris Kauffman | |
| Jerry L. Smith, Chairman of Board | E. Chris Kauffman, Director | |
| Date December 17, 2003 | Date December 17, 2003 | |
| /s/ Robert A. Reece | /s/ Michael A. Cawley | |
| Robert A. Reece, Director | Michael A. Cawley, Director | |
| Date December 17, 2003 | Date December 17, 2003 | |
| /s/ H. Grant Swartzwelder | /s/ Ben D. Hare | |
| H. Grant Swartzwelder, Director | Ben D. Hare, Director | |
| Date December 17, 2003 | Date December 17, 2003 | |
| /s/ Robert O. Lorenz | /s/ Michael C. Coffman | |
| Robert O. Lorenz, Director | Michael C. Coffman, Vice President | |
| Treasurer and Secretary (Principal Financial and | ||
| Date December 17, 2003 | Accounting Officer) | |
| Date December 17, 2003 |
(44)