Forward-Looking Statements and Risk Factors

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1 PHX LISTED NYSE

2 Forward-Looking Statements and Risk Factors This presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of Forward-looking statements include current expectations or forecasts of future events. They may include estimates of oil and gas reserves, expected oil and gas production and future expenses, projections of future oil and gas prices, planned capital expenditures for drilling, leasehold or mineral acreage acquisitions, seismic data, statements concerning anticipated cash flow and liquidity and Panhandle s strategy and other plans and objectives for future operations. Although Panhandle believes the expectations reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to be correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under Risk Factors in Part 1, Item 1 of Panhandle s 2015 Form 10-K filed with the Securities and Exchange Commission. These Risk Factors include the volatility of oil and gas prices; Panhandle s ability to compete effectively against larger independent oil and gas companies; the availability of capital on an economic basis to fund reserve replacement costs; Panhandle s ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil and gas reserves and projecting future rates of production; the amount and timing of development expenditures; unsuccessful exploration and development drilling; declines in the values of our oil and gas properties resulting in write-downs; the negative impact lower oil and gas prices could have on our ability to borrow; current economic conditions worldwide; future legislative or regulating changes; shortages of oilfield equipment, services and qualified personnel; and drilling and operating risks. As Panhandle does not operate any of the properties in which it has an interest, we have very limited ability to exercise any influence over operations of these properties, associated costs or the timing of drilling on its properties. Do not place undue reliance on these forward-looking statements, which speak only as of the date of this release, and Panhandle undertakes no obligation to update this information. Panhandle urges you to carefully review and consider the disclosures made in this presentation and Panhandle s filings with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect Panhandle s business. 2

3 Panhandle Oil and Gas Inc. (PHX) Overview UNCONVENTIONAL BUSINESS MODEL = THE MINERAL ACREAGE ADVANTAGE Non-operator, participating principally with the largest E&P s Selective participation with working interest in most economically attractive opportunities Results in superior returns on diversified asset base Prudent fiscal management Founded in 1926 Public in 1979 No secondary offering in Company history Paid dividend for over 50 consecutive years $288mm market cap (9/22/16) Currently 16.8 million shares outstanding (subsequent to 2 for 1 split in Oct. 2014) 3

4 PHX Business Model Lower Risk, Higher Returns DIRECT OWNERSHIP OF MINERAL RIGHTS = THE MINERAL ACREAGE ADVANTAGE PHX mineral acreage has extremely low cost basis (approximately $90/acre) Minerals ownership lowers PHX well costs verses operators as PHX has no leasehold expense PHX decides whether to participate in wells drilled (working interest) or lease rights (royalty participation only) to the operator (lease bonus income and royalty income) Royalty participation only provides no-risk and no-cost revenues and increases net revenue interest in working interest wells Working interest participation pays proportionate share of drilling, completion and operating costs to receive larger share of well revenues 199,000 mineral acres not currently producing Over 4,600 gross undeveloped drilling locations identified on existing acreage holdings = future opportunities to reinvest cash flow 4

5 PHX Business Model Lower Risk, Higher Returns NON-OPERATED DRILLING PROGRAM = USE MINERAL OWNERSHIP AS LEVERAGE Large mineral acreage ownership position provides diversity in drilling projects without additional acreage costs Leveraged our mineral acreage ownership to participate with a working interest in drilling a significant number of wells Hold working interest in approximately 2,200 producing wells Receive royalty interest in approximately 4,000 additional producing wells 74% of oil and gas sales revenues from working interests and 26% from royalty interest Eagle Ford acreage is HBP leasehold, not minerals PHX not responsible for prospect development costs (i.e. seismic, geological, geophysical and engineering) on working interest wells Drilling financed by cash flow Maintain low cost by paying only for drilling, completion and operating costs of wells; PHX operates with 20 full-time staff, including a complete technical staff 5

6 THE MINERAL ACREAGE ADVANTAGE (Economic Impact of Working Interest Participation on Mineral Acres) Example: Southeastern Oklahoma Woodford Shale Well 1.6 Finding Cost, $/Mcfe Rate of Return, % (BTAX) 28% 30 ASSUMPTIONS: W.I. NRI PHX ownership 5% 5% % Higher Typical ownership 5% 3.75% Reserves 7,045 Mmcf Gross well cost - $4,600, $ % Lower $ % Wellhead prices 7/21/16 NYMEX Strip, adjusted for basis RESULTS % LOWER FINDING COST 75% HIGHER RATE OF RETURN This advantage applies to all plays in which Panhandle drills on owned mineral acres 0 Typical W.I. OwnerPHX Typical W.I. OwnerPHX 0 6

7 Royalty Production and Revenue History $50 $45 $40 $35 $30 Royalty Volume Bcfe Royalty Revenue $Million PHX has over 4,600 identified undeveloped locations and 199,000 mineral acres not currently producing available to feed continued royalty production growth $ $20 $15 $10 $ $

8 Financial Highlights Nine Months Ended June 30, 2016 CONDENSED BALANCE SHEET JUNE 3 0, 2016 Current assets $7,080,155 Property and equipment 441,689,315 Less accumulated DD&A (246,216,837) Net property and equipment 195,472,478 Other 163,918 Total assets $202,716,551 Current liabilities $5,061,729 Long-term debt 49,200,000 Deferred income taxes 30,821,907 Asset retirement obligation, other 2,928,176 Shareholders equity: Stock and paid in capital (16.9 mm shares) 3,366,753 Retained earnings 112,414,741 Deferred directors compensation 3,321,583 Treasury stock (4,398,338) Total liabilities and equity $202,716,551 8

9 Financial Highlights Nine Months Ended June 30, 2016 NINE MONTHS Oil, NGL and natural gas sales $22,557,372 $43,400,839 Lease bonus 7,188,152 1,945,743 Total revenue (1) $28,911,794 $57,427,092 Net income (loss) ($11,024,074) $10,209,022 Earnings per share ($0.65) $0.61 Net cash provided by operating activities (2) $13,058,724 $37,347,802 Capital expenditures - drilling $3,359,518 $23,613,349 Long-term debt $49,200,000 $65,500,000 Mcfe sold 8,817,524 10,508,647 Average Mcfe sales price $2.56 $4.13 (1) 2015 includes $11,706,955 gain on derivative contracts (2) 2016 does not include lease bonus revenues of $7,494,570 9

10 Credit Facility $200 million credit facility, maturity November 2018 $45 million currently outstanding $80 million borrowing base, renewed June 2016 Price Risk Mitigation Through Hedging DURATION MONTHLY VOLUME PRICES OIL Jul-Dec ,000 bbls $35.00 floor/$49.00 ceiling Oct-Dec ,000 bbls $40.00 floor/$47.25 ceiling Oct 2016-Mar ,000 bbls $40.00 floor/$58.50 ceiling Oct 2016-Mar ,000 bbls $45.00 floor/$54.00 ceiling Oct 2016-Mar ,000 bbls $45.00 floor/$55.50 ceiling 10

11 Price Risk Mitigation Through Hedging (continued) DURATION MONTHLY VOLUME PRICES GAS Apr-Oct ,000 mmbtu $1.95 floor/$2.40 ceiling Oct ,000 mmbtu $2.41 swap Oct -Dec ,000 mmbtu $2.75 floor/$3.05 ceiling Oct -Dec ,000 mmbtu $2.90 floor/$3.40 ceiling Oct 2016-Mar ,000 mmbtu $3.20 swap Nov 2016-Mar ,000 mmbtu $2.25 floor/$3.65 ceiling Nov 2016-Mar ,000 mmbtu $2.25 floor/$3.95 ceiling Nov 2016-Mar ,000 mmbtu $2.60 floor/$3.25 ceiling Nov-2016-Apr ,000 mmbtu $2.955 swap Jan-Jun ,000 mmbtu $2.85 floor/$3.35 ceiling Jan-Dec ,000 mmbtu $3.10 swap Jan-Dec ,000 mmbtu $2.80 floor/$3.47 ceiling Jan-Dec ,000 mmbtu 3.00 floor/$3.35 ceiling April-Dec ,000 mmbtu $3.07 swap April-Dec ,000 mmbtu $2.80 floor/$3.35 ceiling April-Dec ,000 mmbtu $2.75 floor/$3.35 ceiling 11

12 PHX Stock Price History Net of Dividends

13 PHX Investment Strategy & Current Activity Maintain the disciplined and consistent long term investment philosophy of investing in projects that we believe will earn reasonable rates of return at NYMEX futures pricing YTD capital investing has been very low due to poor product prices. However, there has been some recent improvement in oil and gas pricing. We are anticipating that our capital investing will grow beginning in the fourth quarter of this fiscal year We continue to earn non-cost bearing royalty interest in all wells drilled on our mineral acreage, whether we participate with a working interest or not We are reducing our debt with the excess cash flow generated from our operations, hedging proceeds, lease bonuses and the sale of a non-strategic property WITH THE GOAL OF CREATING MATERIAL LONG TERM VALUE PER SHARE 13

14 Activity Highlights We leased out ~7,450 mineral acres for ~$7.8 million YTD in FY2016. We also sold a package of ~1,700 immaterial wells that came from the dissolution of partnership for $3.9 million in mid-july 2016 Two Bakken wells which spud in July, 2016 are now producing and our only DUC Eagle Ford well was completed in July. The Bakken wells are producing at comparable rates to the offset wells and the Eagle Ford well has been on sales for 60 days and is materially outperforming the most recent wells on our acreage due to significantly enhanced fracturing techniques Drilling is underway on our first Cochran Co. Texas San Andres well. and the operator of our Andrews/Winkler Texas acreage block is preparing to drill another well in that block January 2017 Southwestern Energy has one rig drilling in the Fayetteville shale. We have historically participated in roughly one of every four wells drilled in that play We elected to participate in 8 significant interest wells in the southeastern Oklahoma Woodford Shale. We will have an average 20% working interest and a 27.4% net revenue interest in the wells. Two of the wells are being drilled. The first four wells are expected to begin producing in late 2016 and the remaining four should begin production in early

15 Permian Basin Andrews & Winkler Counties Project 15

16 Permian Basin Andrews & Winkler Counties Project 16

17 Permian Basin Andrews & Winkler Counties Project Panhandle leased out ~2,440 contiguous net mineral acres on the central basin uplift in Andrews and Winkler Counties, Texas The lease covers a 43.6 square mile area The block has multiple well, stacked pay potential in the Wolfcamp, Strawn, Atoka, Mississippian, Barnett and Woodford The Company generated $1.2 million in lease bonus Panhandle will receive 25% of all production and resulting non-cost bearing revenue, proportionately reduced from the leased property in the form of royalty Panhandle has the right to buy back the lease in each unit as initial unit wells are proposed up to a maximum working interest of 10% With full participation Panhandle (assuming 640 acre units), would have an average 7% working interest and an average 7.5% net revenue interest in all wells drilled on the 43.6 square mile block The first well has been drilled and completed. The well started producing in March, 2016 and has cumulative production of ~ 25,000 Bo. Current production is 100 Bopd The operator is preparing to drill a second 2 mile lateral test well on the block in January,

18 Permian Basin Cochran Co. San Andres Project 18

19 Permian Basin Cochran Co. San Andres Project 19

20 Permian Basin Cochran Co. San Andres Project Panhandle leased out 4,052 contiguous net mineral acres on the northwest shelf of the Midland Basin in Cochran Co. Texas The lease covers a ~34.5 square mile area The operator intends to drill 1.5 mile horizontal San Andres wells at ~5,000 TVD The Company generated $2.1 million in lease bonus Panhandle will receive 25% of all production and non-cost bearing revenue, proportionately reduced, from the leased property in the form of royalty payments Panhandle has the right to buy back the lease in each unit as initial unit wells are proposed up to a maximum working interest of 10% With full participation Panhandle would have a 10% working interest and a 12.1% net revenue interest in all wells drilled on the 34.5 square mile area The operator has proposed two wells. The initial well is being drilled and the location is built for the second well 20

21 Eagle Ford Locator Map PHX 21

22 Eagle Ford Current net production 475 Boepd excluding recent completion 71 producing wells 106 additional undeveloped Eagle Ford locations Proved Reserves 76% Crude Oil, 13% NGL & 11% Natural Gas Mid-Year 2016 proved 4,319 Mbo MbNGL Bcf (34.2 Bcfe, 23.6% of total) The DUC well was completed in July, This well was fracture stimulated with enhanced techniques including the use of significantly more sand and improved diversion. The well produced an average of 1,010 Boe/day (90% oil) for the first 30 days of production and 849 Boe/day for the first 60 days. This compares to 470 Boe/day average for the first 30 days, and 381 Boe/day for the first 60 days from the five most recent wells on our acreage, which were completed in late 2015 * rates adjusted for downtime 22

23 PHX Eagle Ford Shale Leasehold Acreage and Active Wells 23

24 Arkansas Fayetteville Shale 24

25 Arkansas Fayetteville Shale Diverse mineral and leasehold ownership across the play PHX wells primarily operated by Southwestern Energy Current production 8.9 Mmcfe per day Reserves Mid-Year 2016 proved 35.5 Bcfe (25% of total) 2015 probable 43.6 Bcfe (16% of total) 2015 possible 57.6 Bcfe (29% of total) 1,886 undeveloped locations identified Mineral ownership generates superior returns Southwestern has commenced drilling again in the field with one drilling rig 25

26 Arkansas Fayetteville Shale 26

27 S.E. Oklahoma Woodford Shale 27

28 Southeastern Oklahoma Woodford Shale Diverse mineral ownership across the play PHX wells primarily operated by Newfield, Devon, BP and PetroQuest Current production 3.4 Mmcfe per day Reserves Mid-Year 2016 proved 15.5 Bcfe (11% of total) 2015 probable Bcfe (46% of total) 2015 possible 55.7 Bcfe (28% of total) 1,073 undeveloped locations identified Mineral ownership generates superior returns We have elected to participate in eight wells with an average 20% WI and an average 27.4% NRI. These wells will be drilled by BP, an active operator in the area. Two of the wells are being drilled. The first four wells are expected to begin producing in late 2016 and the remaining four should begin production in early 2017 Modern drilling and completion techniques applied to this play have resulted in material well cost reductions and productivity increases as compared to the early development of this field 28

29 Southeastern Oklahoma Woodford Shale Play Outline Newfield, Devon, BP, Petroquest, XTO 29

30 Western & South Central Oklahoma 30

31 STACK, SCOOP and CANA Woodford Plays Diverse mineral ownership across initial plays PHX wells primarily operated by Devon, Cimarex, Continental, Newfield and XTO Current production 4.0 Mmcfe per day Reserves Mid-Year 2016 proved 31.3 Bcfe (17% of total) 2015 probable Bcfe (37% of total) 2015 possible 82.3 Bcfe (41% of total) 1237 undeveloped locations identified Mineral ownership generates superior returns 31

32 SCOOP/STACK/CANA Plays Devon, Continental, Newfield Stack Meramec/ Woodford Devon, Cimarex, Continental Cana Woodford Continental, Newfield, Marathon SCOOP Woodford/Springer XTO 32

33 Asset Pyramid Probable and Possible Reserves Proved Reserves Probable and possible undeveloped reserves on fee mineral acres in the Fayetteville Shale, Oklahoma Woodford Shales and Western Oklahoma/Texas Panhandle horizontal oil plays and held by production leasehold in the Eagle Ford Shale, (superior economics due to royalty retention on mineral acres) ~ 6,200 producing wells, ~50% of revenue from gas, ~50% from oil and liquids in First Half 2016 PUD 37% of total proved reserves, principally on fee mineral acreage and held by production leasehold in shale plays Fee Mineral Acreage Perpetually owned 199,000 acres not producing, 56,400 acres producing 33

34 Reserve Statistics Proved Reserves at Mid-Year 2016 Proved developed reserves Bcfe PUD reserves Bcfe or 37% of total proved reserves Proved SEC flat pricing PV10 - $65.5 million ($2.14/Mcf, $40.07/Bo & wellhead) Proved NYMEX futures pricing PV10 - $103.7 million (NYMEX futures pricing as of March 31, 2016, basis adjusted to the Company wellhead price) Year-End 2015 Inventory of Undeveloped Locations Fiscal Year-End P reserves increased to a record Bcfe, a 20% increase as compared to Year-End Over 4,600 gross undeveloped locations Proved, Probable and Possible Reserve Appraisal Performed by DeGolyer and MacNaughton 34

35 Panhandle Oil and Gas Undeveloped Mineral Acreage Panhandle owns 199,000 acres of undeveloped minerals in 10 states. The minerals are perpetual and we have deeds to them just like a surface land owner The total value of Panhandle s undeveloped mineral holdings is estimated to be in a range from $104 million to $134 million 164,000 acres are located in Oklahoma, Texas, New Mexico and Arkansas The range of estimated valuations is from $25 per acre to $8,600 per acre, based on location. The average is approximately $600 to $800 per acre The total value of these undeveloped mineral holdings is estimated to be in a range from $100 million to $130 million The remaining 35,000 acres of undeveloped minerals are located in Colorado, North Dakota, Kansas, Montana, South Dakota and Florida The range of estimated valuations in these states is from $25 per acre to $2,000 per acre, based on location and the estimated average value is $114 per acre The total value of Panhandle s undeveloped mineral holdings in these states is estimated to be $4 million The information presented in this slide reflects the estimated value of the Company s undeveloped mineral holdings. However, with additional development on and around this acreage, along with advances in knowledge and technology, these perpetual mineral holdings have the potential to generate substantially more long term value for our shareholders 35

36 Panhandle Oil and Gas Undeveloped Mineral Acreage (cont.) Approximately 4,200 acres of the 199,000 undeveloped mineral acres have identified 3P undeveloped locations and reserves associated with them. The 4,200 acres have an estimated acreage value of $8.5 million Additionally, we have only assessed 3P undeveloped reserve potential on approximately 16,400 acres of our 56,400 acres of producing minerals. The vast majority of the undeveloped locations identified on this 16,400 acres are in major shale plays 36

37 Long Term Growth Strategy Panhandle s Primary Goal is to Create Shareholder Value Over the Long Term Wisely invest in wells drilled on our mineral and leasehold acreage funded by cash flow Acquire additional assets that are accretive to share value with cash flow/bank debt/stock Maximize royalty and lease bonus values when not participating in drilling on our mineral holdings Place hedges to protect from commodity price downside Maintain a conservative balance sheet to be prepared for volatility in oil and gas pricing and to also take advantage of the Company's quality investment opportunities 37

38 Appendix Slides PHX LISTED NYSE

39 Net Acres (Thousands) Mineral Holdings Significant Mineral Acreage Holdings OK NM TX ND AR Leasehold 39

40 Quarterly Production MCFE 4,500,000 GAS Equivalent Oil + NGL 4,000,000 3,500,000 3,000,000 2,500,000 2,000,000 1,500,000 1,000, ,

41 Mid-Year 2016 Reserves and YTD Third Quarter 2016 Production and Revenue by Product 120 Gas NGL Oil % 24% 10% 28% 19% 9% 51% 45% 60 6% 40 66% 72% 20 49% 0 Mid-Year 2016 SEC Proved Reserves Fiscal 2016 YTD Production Fiscal 2016 YTD Revenue 41

42 $/Mcfe Unit Costs Per MCFE 8.00 DD&A LOE/Prod Tax G&A Interest Total 3.43 Total 3.40 Total 3.27 Total Total

43 Mcfe/Share Gross Producing Wells Annual Production Per Debt Adjusted Share 2.00 Gas-Mcf Oil & NGL Mcfe 7, ,105 6,019 6,195 6, , ,107 5, , Total Total Total Total Total ,000 2, , Debt Adjusted Shares are Based on Fiscal Year-End Debt and Stock Price All Years Share Count-Adjusted for Stock Splits 0 43

44 Mcfe/Share Proved Reserves Per Debt Adjusted Share Proved Developed Reserves Per Share Proved Undeveloped Reserves Per Share Total Total 6.65 Total 7.05 Total Total Debt Adjusted Shares are Based on Fiscal Year-End Debt and Stock Price All Years Share Count-Adjusted for Stock Splits 44

45 Mcfe/Share 3P Undeveloped Reserves Per Debt Adjusted Share 40.0 Reserves per Share Debt Adjusted Shares are Based on Fiscal Year-End Debt and Stock Price All Years Share Count-Adjusted for Stock Splits 45

46 Year-End 2015 SEC Proved Reserves 46

47 Year-End 2015 SEC Proved Reserves 47

48 Year-End 2015 Proved, Probable and Possible Reserves 48

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