Introduction to the Upstream Sector
Table of Contents 1. Introduction 2. E&P Valuation 3. Understanding the Upstream P&L 4. E&P Ratio Analysis 5. Glossary 6. Additional Resources
1. Introduction
What are Hydrocarbons? Fossil Fuels
Petroleum
Coal
Crude Oil
Conventional Oil APL Range 20-40°
Condensate APL Range > 40°
NGL
1
Natural Gas
Heavy Oil APL Range < 18°
Oil Sands Rock
Dry/Sweet Methane (CH4)
Wet Ethane (C2H4) Propane (C3H8) Buthane (C4H10)
NGL
Sour Contains Hydrogen Sulfide (H10)
Common Uses for Hydrocarbons Hydrocarbons: Organic compounds of hydrogen and carbon atoms providing the basis of all petroleum products. Hydrocarbons exist in a solid, liquid, or gaseous state. Crude Oil = Primary Transportation Fuel
Natural Gas = Electricity Generation
Fuels made from one barrel of crude (42 Gallons) – Gasoline – Diesel – Jet Fuel – Other
Also used to produce – Glass – Paper – Brick – Paints – Fertilizer – Plastics – Antifreeze – Explosives
Distillates/Heavy Fuel Oil - 5
Other products made from oil – Ink – Plastics – Dishwashing liquids – Deodorant – DVDs – Tires
Oil and Natural Gas are not substitute products; there is no arbitrage opportunity from pricing anomalies 2
Spindletop, TX, 1901: The Birth of Modern Energy
3
http://www.priweb.org/ed/pgws/history/spindletop/spindletop.html
Energy Value Chain
Production
Processing
Transportation
Marketing
Refining
Marketing
Natural Gas
Exploration Crude Oil
4
Production
Transportation
Upstream
Midstream
Downstream
Illustrative Well Production Profile An E&P company owns declining assets that generate attractive cash-on-cash returns. Effective redeployment of that cash is the key to generating return for shareholders.
Daily Production (MMcfe / d)
5,000 Initial Drilling & Completion (D&C) Cost: $5.00 million Initial Production Rate (IP): 4.5 MMcfe/d Estimated Ultimate Recovery (EUR): 6.5 Bcfe
4,000
PV-0: $10.3 million PV-10: $3.7 million
3,000
Internal Rate of Return: 57% Net Finding & Development Cost (F&D): $0.96 / Mcfe
2,000 1,000 0 2
52
102
152 Months
5
202
252
302
Oil and Gas Reserve Classification Oil and Gas Reserves
Proved (1P)
Unproved
Possible
Probable
Four Classes of Reserves Proved, probable, possible and potential
Developed (PD)
Undeveloped (PUD)
Non-Producing (PDNP)
Main difference between classifications involves level of certainty that such reserves will be produced as well as costs involved to develop them Proved reserves is only class where one definition has developed general acceptance among petroleum engineers Proved Reserves = 1P 1P + Probable Reserves = 2P 2P + Possible Reserves = 3P 6
Behind-Pipe (PDBP)
Shut-In (PDSI)
Producing (PDP)
Commodity Prices Over Time
25.0x
$120
20.0x
$90
15.0x
$60
10.0x
$30
5.0x
$0 11/01/01
0.0x 07/02/03
03/02/05 WTI 1-Yr FWD
7
11/01/06 HH 1-Yr FW D
07/01/08 Oil / Gas Ratio
03/02/10
11/01/11
Gas Price ($ / Mcfe)
$150
Oil / Gas Ratio
Oil Price ($ / Bbl)
Historical relationships between oil and gas prices changed beginning in 2008 due to the emergence of shale gas.
Gas to Oil Energy Equivalent Conversion Conversion 6 Mcf of gas = 1 Boe: Usual ratio adopted to convert gas to oil and vice versa Because of differences in heating value and liquids content of gas, there is no one right oil/gas conversion ratio However, using 1,000 BTU per Mcf convention, ratio most often used for dry gas is 6,000 cf per barrel of oil equivalent or 6 Mcf/Boe Table of Gas / Oil Conversions Gas Volume
Oil Equivalent
Gas Volume
Oil Equivalent
1 Mcf
=
0.1667 Boe
1 BCF
=
166,667 Boe
6 Mcf
=
1.0 Boe
6 BCF
=
1 MMBoe
1 MMcf
=
166.7 Boe
1 TCF
=
166.7 MMBoe
6 MMcf
=
1.0 MBoe
6 TCF
=
1 BBoe
10 MCF = 1 Boe Convention: Occasionally, companies will convert their gas to oil equivalent using a ratio other than a 6:1 ratio – Historically, 10:1 has been used to better reflect the economic equivalence of gas to oil (i.e. gas less valuable) – 6:1 reflects strict calorific equivalence – 10:1 is actually standard reporting equivalence in Canada
8
Proved Reserves Disclosure
9
Illustrative Valuation Exercise ($ in millions, except per-unit amounts) Share Price Shares % of 52-Week High % of 52-Week Low
$81.09 116.800 76% 146
Equity Value Plus: Debt Less: Cash Other A djustments Firm V alue
$9,471 2,563 (521) 109.4 $11,623
Operating Metrics Proved Reserves (MMBoe) PV-10
987 $4,894
V aluation Metrics ($ / Boe) Firm Value / PV -10
$11.77 2.4x
10
SEC PV-10 Disclosure
11
Costs Incurred Disclosure
12
2. E&P Valuation
Valuation Overview
Future Development Opportunities Value
Firm Value
Proved Reserves Value
13
Wide Range of Valuation Methodologies Method
Typical Market Focus
NAV / DCF
M&A Market Focus
FV / EBITDA Financial Multiples
P/E
P / CFPS
$ / Boe of Reserves
$ / Net Acre
14
Suitability
E&P sector focus Core value to defined field and risked exploration / prospect upside Reserve report may provide material guidance
Widely understood and used in traditional industries with high earnings visibility Used a cross – check to NAV Not for E&P companies
Used instead of PE due to accounting differences between companies
Scoping value methodology Often used on risked basis for upside value Comparability dependent on reserves classification
Can be used with precedent transactions to value emerging plays Should be calculated net of any associated production value
? ?
Valuation Methodologies NAV / DCF analysis incorporates operating characteristics of upstream assets, and is the most commonly used valuation methodology; multiple-based valuation provides market-based reference points. Pros
NAV / DCF
Cons
▲ Allows incorporation of operating characteristics of the asset, based on granular and detailed analysis
▼ Requires considerable data gathering, e.g. host government, geophysicists, petroleum engineers, tax advisors, etc
▲ Factors any associated risks into the value of the asset
▼ Estimation of expected production profile and revenues involves a certain degree of uncertainty and risk
▲ Enables sensitivity analysis based on specific parameters ▼ Not applicable in M&A transactions; does not factor in acquisition premium Trading Comparables
▲ Reflects asset value as an ongoing operation ▲ Proxy for value based on industry average
▼ Does not factor in specific operating or risk characteristics of the asset ▼ Comparables universe difficult to determine ▼ Applicability limited to M&A transactions due to inclusion of acquisition premium
Precedent Transactions
15
▲ Good proxy in M&A transactions; factors acquisition premium ▲ Proxy for value based on industry average
▼ Does not factor in specific operating or risk characteristics of the asset ▼ Comparables universe difficult to determine
NAV Methodology: Assumptions Methodology
Citi evaluated the net asset value (NAV) of Ultra Petroleum’s oil and gas assets in the Marcellus Shale and the Pinedale and Jonah Fields in Wyoming –
Well economics drilled in Jonah assumed to be the same as Pinedale wells
NAV calculated based on a development plan built up from a projected rig count, current acreage, and applying an assumed type curve and well-level assumptions
Oil Gas
Pinedale / Jonah
Source
Marcellus
Current PDP based on historical drilling to more accurately capture PDP decline curve versus a linear decline
EUR (Bcfe)
4.8
HPDI
Type Curve
--
HPDI
--
3/7/11 Investor Presentation and peer decline rates --
($14.50)
UPL 2008 Reserve Report
--
Gas Differential to HH (%)
92%
3/7/11 Investor Presentation
102%
Production Taxes (% of Rev)
12%
UPL 3Q10 Transcript
5%
LOE ($ / Mcfe) (2)
$0.46
UPL 3Q10 Transcript
$0.24
UPL 3Q10 Transcript
$0.29 (3)
UPL 3Q10 Transcript
Included in LOE and Capex
UPL 3Q10 Transcript
Resource potential based on public guidance
Capex assumption based on public guidance
Gathering and Transportation Cost ($ / Mcfe)
NAV to be modeled in real terms (no inflation)
Gross Well Cost ($mm)
Further adjustments to account for the hedge program, the decrease in value attributable to G&A needs of a going concern, non-drilling capex, and income taxes
2011 2012 2013 2014 2015 >2016 $110.77 $109.41 $105.81 $103.53 $102.46 $102.46 4.44 4.93 5.31 5.65 6.03 6.03
3/7/11 Investor Presentation
Oil Differential to WTI ($)
Base case price assumption based on 4/15/11 NYMEX strip for 2011-15, held constant in 2016 and beyond
Source
4.2(1)
The calculated NAV of each asset is based on the assumption shown to the right –
Assumptions
Working Interest (%) NRI (8 / 8ths) Spud to Spud (days) Undeveloped Net Acreage Well Spacing (Acres) Gross Well Locations (5)
(1) Weighted average of North and South assuming ~65% North composition. Net Remaining Well Locations (2) Includes $0.25/mcfe of gathering expense. (3) REX transportation cost reflected at the corporate level. (4) Based on company disclosed net wells / gross wells. 16 (5) Pinedale wells based on company disclosed total gross wells as of 12/31/09 less wells brought online in 2010. Marcellus gross well locations based on 3,000 net locations and a 45% working interest.
3/7/11 Investor Presentation Peer assumption
$4.6
3/7/11 Investor Presentation
$4.8(1)
3/7/11 Investor Presentation
55.5% (4)
1/12/11 Investor Presentation
45.0%
1/12/11 Investor Presentation
80%
UPL 2008 Reserve Report
86%
17
3/7/11 Investor Presentation
10
44,000
Company 10K
260,000
11/4/10 UBS Research UPL 3Q10 Transcript Company 10K
7
5-10 acres; UPL 4Q10 Transcript
80
UPL 3Q10 Transcript
5,335
1/12/11 Investor Presentation
6,667
Net Wells / Working Interest
2,964
1/12/11 Investor Presentation
3,000
UPL 4Q10 Transcript
NAV Methodology: Development Profile Total Net Drilling Locations Development Plan by Play (Targeted Development) Total =
6,007 (1)
Ne t We lls Drille d Pinedale Marcellus Total Net Wells
Pinedale 45% Marcellus 55%
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
>2020
119 82
119 82
119 82
119 82
119 82
119 82
119 82
119 82
119 82
119 82
1,814 2,178
3,006 3,000
201
201
201
201
201
201
201
201
201
201
3,992
6,007
Total
Annual Production Profile by Play (Bcfe) 2011 Ne t Production by Are a (Bcfe ) PDP 163 (2) Pinedale 54 (2) Marcellus 33 Total Net Prod. UPL Guidance
Future Resource Potential (Targeted Development)
250 250
2012
2013
2014
2015
2016
2017
2018
2019
2020
>2020
100 119 71
75 161 94
69 193 112
63 219 127
60 242 140
57 261 151
55 279 161
53 295 171
51 310 180
999 9,412 9,597
1,744 11,545 10,837
290 290
329 330
373 --
409 --
441 --
470 --
495 --
518 --
541 --
20,008 --
24,125 --
Daily Production Profile by Play (MMcfe/d) 1,600
Marcellus 48%
22,381
PDP
Pinedale
Marcellus
(2)
Pinedale 52%
1,400 Net Production (MMcfe/d)
Total (Bcfe) Total =
Total
1,200 1,000 800 600 400 200 0 2011
17
2012
2013
2014
2015
2016
2017
2018
2019
2020
Notes: (1) Pinedale wells based on company disclosed total gross wells as of 12/31/09 less expected wells brought online in 2010 (55% working interest). Marcellus gross well locations based on 3,000 net locations and 45% working interest per 4Q10 transcript. (2) Excludes PDP of 1,744 Bcfe.
NAV Methodology: Financial Summary ($ in millions) Net Production (MMcfe) Oil (MBbl) Gas (MMcf)
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
1,570 240,957
1,608 280,426
1,746 318,939
1,969 361,673
2,155 396,318
2,328 427,258
2,486 454,622
2,629 479,174
2,762 501,837
2,888 523,302
3,008 543,232
250,376 250,000 686 17.2%
290,077 290,000 795 15.9%
329,413 330,000 903 13.6%
373,489
409,250
441,227
469,537
494,948
518,407
540,633
561,281
$110.77 4.44
$109.41 4.93
$105.81 5.31
$103.53 5.65
$102.46 6.03
$102.46 6.03
$102.46 6.03
$102.46 6.03
$102.46 6.03
$102.46 6.03
$102.46 6.03
$754 250 149
$508 596 357
$403 855 510
$391 1,083 646
$382 1,304 780
$361 1,440 860
$345 1,558 930
$332 1,664 993
$319 1,761 1,051
$311 1,851 1,105
$306 1,933 1,155
Total Oil and Gas Revenue Hedging Revenue
$1,153 148
$1,460 9
$1,769 0
$2,120 0
$2,467 0
$2,661 0
$2,834 0
$2,989 0
$3,132 0
$3,267 0
$3,393 0
Total Revenue $/mcfe (excl hedges) $/mcfe (incl hedges)
$1,302 $4.61 5.20
$1,470 $5.07 5.07
$1,769 $5.37 5.37
$2,120 $5.68 5.68
$2,467 $6.03 6.03
$2,661 $6.03 6.03
$2,834 $6.04 6.04
$2,989 $6.04 6.04
$3,132 $6.04 6.04
$3,267 $6.04 6.04
$3,393 $6.05 6.05
Operating Costs Production and Property Taxes LOE Corporate Transportation Costs G&A
$162 70 61 24
$105 161 63 24
$81 225 68 24
$77 278 75 24
$74 327 81 24
$70 361 87 24
$67 390 92 24
$64 416 96 24
$62 441 100 24
$60 463 104 24
$59 483 108 24
Total Operating Costs Total Op Costs $/mcfe
$318 $1.27
$353 1.22
$398 1.21
$455 1.22
$506 1.24
$542 1.23
$573 1.22
$601 1.21
$627 1.21
$652 1.21
$675 1.20
Total Net Production (MMcfe) Company Guidance Daily Production (MMcfe/d) % Growth NYMEX Price Deck Oil ($ / Bbl) Gas ($ / Mcf) Realized Sales Proved Pinedale Marcellus
2011
1,023 13.4%
1,121 9.6%
1,209 7.8%
1,286 6.4%
1,356 5.4%
1,420 4.7%
1,481 4.3%
1,538 3.8%
EBITDA EBITDA Margin $/mcfe
$983 76% $3.93
$1,116 76% $3.85
$1,371 78% $4.16
$1,666 79% $4.46
$1,960 79% $4.79
$2,119 80% $4.80
$2,261 80% $4.81
$2,387 80% $4.82
$2,505 80% $4.83
$2,615 80% $4.84
$2,718 80% $4.84
Less: Interest $/mcfe
$89 $0.35
$88 $0.30
$87 $0.26
$87 $0.23
$84 $0.21
$79 $0.18
$74 $0.16
$65 $0.13
$53 $0.10
$33 $0.06
$20 $0.04
Less: Cash Taxes $/mcfe Capex Pinedale D&C Marcellus D&C
$0 $0.00
$38 $0.13
$118 $0.36
$216 $0.58
$318 $0.78
$371 $0.84
$420 $0.90
$467 $0.94
$511 $0.99
$555 $1.03
$596 $1.06
$547 393
$552 395
$547 395
$549 393
$549 395
$549 395
$549 393
$547 395
$549 393
$549 395
$549 395
$940
$947
$942
$942
$945
$945
$942
$942
$942
$945
$945
$43
$224
$420
$613
$725
$824
$913
$998
$1,083
$1,158
$4,135
$4,696
$5,854
Total Capex Free Cash Flow Cash Balance Total Debt Debt / EBITDA
18
($45) $71 $1,605 1.6x
$71 $1,562 1.4x
$293
$713
$1,226
$1,889
$2,597
$3,310
$1,560 1.1x
$1,560 0.9x
$1,460 0.7x
$1,398 0.7x
$1,282 0.6x
$1,082 0.5x
$909 0.4x
$387 0.1x
$387 0.1x
NAV Methodology: Net Asset Value Base Price Case: PV-10 based on Strip Price Deck(1) Current Price (04/15/11)
$48.12
$16,000 $13,909 $12,000
$13,909
$4,916
$1,489
$12,562
$244
$12,420
$142
$12,319
$8,993
Implied Share Price
$10,726
$1,593
$70.01
$10,726
Relative to Current
$8,000 $6,124 $4,000
45%
$2,870 $2,870
$0 P DP (P V-10)
Net Resource (Bcfe)
1,744
Ro ckies (P V-10) M arcellus (P V10)
11,545
10,837
Base Price Case PV-10 Marcellus (excl PDP) 35%
Total Resource Value
Net Debt
Hedges
G&A
(2)
Income Taxes
Asset Value
PDP
Rockies
Marcellus
$6,422
$41,144
$54,432
$20,276
$1.65
$0.53
$0.45
$0.58
24,125
Base Case Valuation Metrics Total PDP 21%
Valuation Metrics PV 10 / 2011E Production ($ / mcfe/d) PV-10 / Resources ($ / mcfe) PV-10 / Risked Resources ($ / mcfe)
(4)
Total
$1.65
$0.38
$0.33
$0.48
NA
$139,171
$18,907
NA
PV-10 / Acre ($ / acre) Rockies (excl PDP) 44%
19
(3)Net
Notes: (1) 5-year NYMEX strip prices as of 4/15/11. (2) Assumes 2010 G&A capitalized at 10x. (3) Cash taxes post G&A. Discounted at 10%. Assumes 40% income tax rate. (4) Assumes 75% location risking (no change to PDP value or production). Rockies and Marcellus risked PV-10 of $3,284mm and $2,685mm.
NAV Methodology: Single-Well Analysis Type Curve Profile 4.20 0% / 100% / 0% 6.03 (2) $0.00 102.0% 45.0% 86.0% $4,800 $1.33 0.24 5.0% 40.1% $6,213 2,072 $0.49
Gross EUR (Bcfe) % Oil, Gas, NGL 1-day IP Rate (MMcfe/d) Differential (Oil) Differential (Gas) Com pany Working Interest Net Revenue Interest Gross Capex per Well ($ in thousands) Net F&D Costs ($/mcfe) Net LOE ($/m cfe) Production Taxes IRR (NYMEX strip) PV-0 ($ in thousands) PV-10 ($ in thousands) PV-10 /(MMcfe)
Marcellus
10,000 Production (Mcfe / d)
Single Well Profile (8/8ths)
Avg. Daily Prod. Decline Rate
Months 36
1
12
24
5,015 --
1,325 (74%)
881 (34%)
685 (22%)
48
60
571 (17%)
495 (13%)(1)
1,000
100
10 1
51
101
151 Months
201
251
301
Return Sensitivities
20
3.200 13.4% 18.0 23.2 29.2 35.9 43.3
Strip
21.1%
40.1%
32.9%
Well EUR (Bcfe) 3.700 4.200 4.700 18.8% 25.2% 32.5% 25.1 33.5 43.2 32.3 43.1 55.8 40.6 54.2 70.3 49.9 66.9 87.1 60.5 81.3 106.5 31.1%
40.1%
50.3%
27.5% 5.200 40.9% 54.5 70.5 89.3 111.2 136.7 61.9%
($/Bbl / $/MMBtu)
$3,800 3.5x $70.00 / $4.00 3.9 $80.00 / $4.50 4.4 $90.00 / $5.00 4.8 $100.00 / $5.50 5.3 $110.00 / $6.00 5.8 $120.00 / $6.50 Strip
($/Bbl / $/MMBtu)
$70.00 / $4.00 $80.00 / $4.50 $90.00 / $5.00 $100.00 / $5.50 $110.00 / $6.00 $120.00 / $6.50
50.0%
Commodity Price
64.5%
ROI
Commodity Price
($/Bbl / $/MMBtu)
Capex per Well ($ in thousands) $3,800 $4,300 $4,800 $5,300 $5,800 42.8% 32.3% 25.2% 20.1% 16.3% $70.00 / $4.00 57.1 43.0 33.5 26.7 21.8 $80.00 / $4.50 73.9 55.4 43.1 34.4 28.0 $90.00 / $5.00 93.6 69.9 54.2 43.2 35.2 $100.00 / $5.50 86.6 66.9 53.2 43.3 $110.00 / $6.00 116.8 105.8 81.3 64.5 52.4 $120.00 / $6.50 143.7 Strip
($/Bbl / $/MMBtu)
Commodity Price
Commodity Price
IRR
$70.00 / $4.00 $80.00 / $4.50 $90.00 / $5.00 $100.00 / $5.50 $110.00 / $6.00 $120.00 / $6.50 Strip
4.9x 3.200 2.1x 2.4 2.6 2.9 3.2 3.5 2.8x
Capex per Well ($ in thousands) $4,300 $4,800 $5,300 $5,800 3.1x 2.7x 2.5x 2.3x 3.5 3.1 2.8 2.6 3.9 3.5 3.1 2.9 4.3 3.8 3.5 3.2 4.7 4.2 3.8 3.5 5.1 4.6 4.1 3.8 4.3x
3.5x
3.2x
Well EUR (Bcfe) 3.700 4.200 4.700 2.4x 2.7x 3.1x 2.7 3.1 3.5 3.1 3.5 3.9 3.4 3.8 4.3 3.7 4.2 4.7 4.0 4.6 5.1
5.200 3.4x 3.8 4.3 4.7 5.2 5.6
3.4x
3.9x
3.9x
4.3x
4.8x
Source: Company filings, investor presentations. Note: Reflects NYMEX strip pricing as of 4/15/11. (1) Terminal decline rate = ~5%. (2) Based on average IP rate of producing wells as of 12/31/10. 2010 average 1-day IP rate of 6.4MMcfe/d and 5.66MMcfe/d based on early Marcellus well per company investor presentation.
NAV Methodology: Consolidated Reserve Summary ($m), unless otherwise noted
Year
21
Gross Wells Drilled
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Rem.
396 399 397 397 398 398 397 397 397 398 398 397 397 399 396 6,120
Total
12,081 -
Net Wells Drilled 201 202 201 201 202 202 201 201 201 202 202 201 201 202 201 2,985 6,007 -
Revenue Natural Gas ($M)
Net Production Oil Natural Gas (MBbls) (MMcf)
Total Net Production (MMcfe)
1,570 1,608 1,746 1,969 2,155 2,328 2,486 2,629 2,762 2,888 3,008 3,118 3,217 3,312 3,394 73,519
240,957 280,426 318,939 361,673 396,318 427,258 454,622 479,174 501,837 523,302 543,232 561,800 578,731 595,244 609,750 16,581,507
250,376 290,077 329,413 373,489 409,250 441,227 469,537 494,948 518,407 540,633 561,281 580,509 598,032 615,115 630,112 17,022,618
111,709
23,454,769
24,125,025
Benchmark Com m odity Prices Oil Natural Gas ($/bbl) ($/mcf) $110.77 109.41 105.81 103.53 102.46 102.46 102.46 102.46 102.46 102.46 102.46 102.46 102.46 102.46 102.46 102.46
$4.44 4.93 5.31 5.65 6.03 6.03 6.03 6.03 6.03 6.03 6.03 6.03 6.03 6.03 6.03 6.03
Realized Com modity Prices Oil Natural Gas NGL ($/bbl) ($/mcf) ($/bbl) $96.27 94.91 91.31 89.03 87.96 87.96 87.96 87.96 87.96 87.96 87.96 87.96 87.96 87.96 87.96 96.27
$4.16 4.66 5.05 5.38 5.75 5.75 5.75 5.75 5.76 5.76 5.76 5.76 5.76 5.76 5.76 5.86
$0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Total Revenue ($M)
Production Taxes ($M)
Lease Op Expense ($M)
Transpo Costs ($M)
Field Level EBITDA ($M)
Drilling and Com pletion ($M)
Field Level Cash Flow ($M)
Discounted CF PV-10 ($M)
($80,469) 184,600 453,241 747,717 1,040,026 1,199,315 1,342,564 1,469,767 1,586,514 1,695,224 1,798,105 1,896,234 1,984,313 2,064,627 2,147,278 73,007,624
($78,769) 159,410 356,090 534,900 676,739 709,492 722,156 718,798 705,367 685,030 660,616 633,371 602,548 569,816 538,778 5,714,525
Year
Oil ($M)
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Rem.
$151,132 152,652 159,391 175,319 189,585 204,780 218,663 231,252 242,929 254,061 264,598 274,265 282,965 291,309 298,507 7,077,449
$1,001,975 1,307,783 1,609,219 1,945,167 2,277,006 2,456,421 2,615,035 2,757,393 2,888,816 3,013,239 3,128,667 3,236,307 3,334,566 3,430,411 3,514,790 97,209,313
$1,153,108 1,460,435 1,768,610 2,120,486 2,466,590 2,661,201 2,833,698 2,988,645 3,131,745 3,267,300 3,393,265 3,510,573 3,617,531 3,721,720 3,813,297 104,286,761
$125,961 149,111 175,616 208,448 240,648 258,501 274,381 288,620 301,759 314,248 325,921 336,721 346,486 355,990 364,214 8,812,407
$106,563 117,088 130,280 146,723 159,987 171,887 182,448 191,913 200,644 208,938 216,678 223,849 230,342 236,668 242,154 5,939,498
$61,259 62,573 67,519 75,250 81,421 86,990 91,955 96,392 100,480 104,382 108,052 111,421 114,437 117,372 119,858 2,444,000
$859,324 1,131,663 1,395,195 1,690,065 1,984,534 2,143,823 2,284,912 2,411,720 2,528,862 2,639,732 2,742,613 2,838,582 2,926,266 3,011,690 3,087,071 87,090,857
$939,793 947,063 941,953 942,348 944,508 944,508 942,348 941,953 942,348 944,508 944,508 942,348 941,953 947,063 939,793 14,083,233
Total
$10,468,855
$135,726,108
$146,194,963
$12,879,033
$8,705,659
$3,843,361
$120,766,910
$28,230,229
$92,536,680
$13,908,868
Public Comparables Methodology: Overview Peer Median
($ in millions)
UPL
RRC
EQT
QEP
COG
XCO
Share Price (as of 04/15/11)
$48.21
$39.64
$26.29
$53.40
$46.96
$38.34
$53.23
$20.74
Equity Value Plus: Debt Less: Cash Other Adjustments (1) Enterprise Value
$7,377 1,560 (71) 0 $8,866
$13,897 1,094 (16) 0 $14,975
$8,046 2,607 (56) 217 $10,815
$8,674 1,061 (3) 155 $9,887
$7,034 2,003 0 191 $9,228
$6,797 1,531 0 97 $8,425
$5,551 975 (56) 0 $6,470
$4,546 1,310 (206) 379 $6,029
$6.17 6.85
$4.66 5.94
$3.53 4.93
$4.49 5.72
$5.09 6.08
$6.48 7.87
$5.40 7.29
$2.62 3.71
$941 1,045
$1,622 2,064
$1,068 1,492
$721 919
$759 907
$1,143 1,388
$564 760
$559 793
$1,024 1,141
$1,684 2,079
$1,378 1,779
$827 1,022
$835 1,011
$1,255 1,489
$642 837
$599 840
Operating Metrics 2011E Cash Flow per Share (3) 2012E Cash Flow per Share (3) 2011E Cash Flow 2012E Cash Flow
(3) (3)
2011E EBITDA (3) 2012E EBITDA (3) Proved Reserves (Bcfe) % Proved Developed % Gas
HK
53% 97
4,937 55% 100
3,392 35% 92
4,442 49% 80
5,220 49% 100
3,031 53% 86
2,701 64% 98
1,499 55% 97
622 705 840 19.3x 7.7
12.2x 6.5
1,211 1,624 1,530 11.2x 6.1
762 877 1,080 12.2x 4.3
428 560 705 28.4x 14.0
438 477 567 32.7x 15.9
678 717 816 12.2x 6.5
407 481 564 18.2x 11.6
385 500 679 10.7x 5.8
$1,489 1.5x 1.3 $0.85 $2,112 1,773
1.4x 1.1 $0.79 $2,135 1,629
$1,078 0.6x 0.5 $0.40 $664 705
$2,551 1.9x 1.4 $2.15 $2,910 2,361
$1,058 1.3x 1.0 $0.48 $1,888 1,499
$2,003 2.4x 2.0 $0.79 $4,202 3,532
$1,531 1.2x 1.0 $0.95 $2,135 1,876
$919 1.4x 1.1 $0.53 $1,910 1,629
$1,105 1.8x 1.3 $1.34 $2,208 1,626
Valuation Metrics Price / 2011E CFPS 2012E CFPS
7.8x 7.0
8.5x 6.7
8.5x 6.7
7.4x 5.3
11.9x 9.3
9.2x 7.7
5.9x 4.9
9.8x 7.3
7.9x 5.6
Firm Value / 2011E EBITDA 2012E EBITDA
8.7x 7.8
10.1x 7.2
8.9x 7.2
7.8x 6.1
11.9x 9.7
11.0x 9.1
6.7x 5.7
10.1x 7.7
10.1x 7.2
Current Production (MMcfe/d) (2) 2011E Production (MMcfe/d) (3) 2012E Production (MMcfe/d) (3) Proved R / P (2) Proved Developed R / P Credit Statistics Net Debt / 2011E EBITDA 2012E EBITDA Proved Dev. Reserves ($ / Mcfe) 2011E Daily Production ($/ Mcfe/d) 2012E Daily Production ($/ Mcfe/d)
Proved Reserves ($ / Mcfe) 2011 Production ($ / Mcfe/d) 2012 Production ($ / Mcfe/d)
4,390 40% 96
SWN
$2.02 $12,578 10,556
$2.78 $12,338 10,327
$3.03 $9,219 9,786
$3.19 $12,338 10,009
Source: Company filings, investor presentations, Wall Street research. Market data as of 4/15/11. (1) Includes adjustments related to non-controlling interest and investments in affiliates. Based on Q4 2010 production. (3) Per Wall Street mean consensus estimates.
22 (2)
$2.23 $17,646 14,016
$1.77 $19,363 16,273
$2.78 $11,748 10,327
$2.40 $13,446 11,471
$4.02 $12,055 8,878
Precedent Reserves Transactions Methodology: Overview Date
Acquiror
Target / Seller
Location
2010/03/18 Opon International Fidelity E&P; MDU 2010/03/15 Resources 2009/08/10 Williams Companies
Delta Petroleum
Piceance
Undisclosed
2009/03/03 Undisclosed 2008/11/03 Devon
Chevron Chicago Energy Associates Dominion Laramie Energy Koch Exploration Undisclosed Undisclosed
Uinta Piceance Piceance Piceance Green River Basin
2004/12/06 Berry Petroleum
J-W Operating Company
2004/09/01 2004/08/27 2004/08/27 2004/07/22 2004/06/29 2003/06/06
Calpine Undisclosed Calpine Various SG Interests MarkWest
2008/05/05 Whiting 2007/06/04 2007/04/18 2006/03/09 2006/01/27 2005/02/23
XTO Plains E&P Black Hills Berry Petroleum Whiting
Bill Barrett Pogo Producing Pogo Producing Western Gas Energen XTO
2003/04/09 XTO 2003/03/11 2002/11/25 2002/11/06 2002/08/01 2002/04/18 2002/04/11 2002/04/01 2001/01/09
Sacramento Municipal Utility District XTO Westport Resources EnCana EnCana MRO; XTO Bill Barrett Texaco
2000/10/25 Barrett Resources
Transaction Value ($ MM)
(Bcfe)
R/P
Transaction Value / Reserves Daily Prod. ($ / Mcfe) ($ / Mcfe/d)
Adj. Transaction Value / (1) Reserves Daily Prod. ($ / Mcfe) ($ / Mcfe/d)
$400
32
9.2
95%
NA
9.5
$3.22
$11,124
$3.03
$10,486
Green River Basin
113
63
14.5
92
81
11.9
1.49
6,464
1.40
6,091
Orion Energy
Piceance
258
150
24.0
100
NA
17.1
0.65
4,031
0.55
3,448
Berry Petroleum
Denver-Julesburg (D-J)
154
126
18.0
100
NA
19.2
1.11
7,778
1.00
7,035
Uinta
779
210
40.0
100
66
14.4
3.71
19,483
2.34
12,268
365
115
19.0
98
22
16.6
3.17
19,211
1.34
8,136
2,500 945 51 159 65
1,060 384 40 26 50
200.0 36.0 1.9 1.0 6.3
95 97 100 100 98
64 NA 22 NA 68
14.5 29.2 57.0 71.2 22.0
1.69 2.13 1.27 3.19 1.29
8,937 22,692 26,500 83,000 10,317
0.96 1.22 0.69 1.57 0.91
5,075 12,961 14,415 40,886 7,310
Denver-Julesburg (D-J)
105
87
8.8
100
39
27.1
1.21
11,932
0.84
8,348
Piceance San Juan Basin San Juan Basin San Juan Basin San Juan Basin San Juan Basin Raton/Hugoton/San Juan
137 106 83 82 263 61
50 56 44 60 240 50
NA 8.4 6.6 NA NA 9.5
98 100 100 100 80 100
56 NA NA NA 50 NA
NA 18.3 18.3 NA NA 14.4
2.74 1.89 1.89 1.37 1.03 1.21
NA 12,607 12,591 NA NA 6,369
2.16 1.40 1.40 1.00 1.10 0.87
NA 9,354 9,342 NA NA 4,585
400
311
60.0
100
77
14.2
1.20
6,232
1.06
5,499
El Paso
San Juan Basin
138
163
16.0
100
NA
28.0
0.84
8,625
0.65
6,634
JM Huber El Paso Williams Companies El Paso CMS Energy Williams Companies EnerVest
San Juan Basin Uinta Jonah Field Piceance Powder River Basin Wind River San Juan Basin
160 502 350 293 101 74 121
154 600 395 300 110 58 204
29.0 80.0 106.7 38.0 14.0 27.9 21.5
100 100 96 85 100 100 100
79 47 68 NA NA NA NA
14.5 20.5 10.1 21.6 21.6 5.7 26.0
1.04 0.84 0.79 0.93 0.67 1.23 0.53
5,517 6,275 2,911 7,349 5,253 2,573 5,056
1.16 0.98 1.12 1.50 0.88 1.57 0.38
6,156 7,369 4,151 11,872 6,909 3,280 3,559
53
75
5.2
100
20
39.5
0.65
9,309
0.65
9,437
98% 100
54% 22.5 60 18.3
$1.53 1.22
$12,886 8,625
$1.21 1.08
$8,984 7,310
Williams Companies
Uinta
Kansas City Power & Light Raton Basin
Mean Median
23
Proved Reserves (MMcfe/d) % Gas % PD
Source: John S. Herold, Inc. (1) Adjusted based on 12/7/10 strip of $89.90 / Bbl and $4.54 / MMBtu
Precedent Acreage Transactions Methodology: Overview Date
Acquiror
Target / Seller
Location
2010/11/15 2010/11/09 2010/10/06 2010/09/22 2010/08/31 2010/07/20 2010/08/05 2010/05/28 2010/05/28 2010/05/10 2010/04/21 2010/04/09 2010/03/26 2010/03/15 2010/03/02 2010/02/16 2010/01/19 2009/12/21 2009/10/29 2009/09/30 2009/09/30 2009/09/18 2009/08/19 2009/06/22 2009/06/09 2008/11/11 2008/11/04 2008/06/30 2008/04/15
Newfield Exploration Chevron Chesapeake Energy Atinum Partners Sumitomo Trans Energy Reliance Industries Royal Dutch Shell Penn Virginia BG Group Atlas, Reliance Reliance Industries Statoil Hydro CONSOL Energy EQT Mitsui Chesapeake Energy Ultra Petroleum Magnum Hunter Resources Chesapeake Energy Fortuna Energy Undisclosed Enerplus Resources Williams Companies Kohlberg Kravis Roberts Statoil Hydro Carrizo Oil & Gas Antero Resources XTO Energy
EOG Resources Marcellus Atlas Energy Marcellus Marcellus Anschutz Exploration Gastar Exploration Marcellus Rex Energy Marcellus Republic Energy Marcellus Carrizo Oil & Gas Marcellus East Resources / Kohlberg Kravis Roberts Marcellus Marcellus Undisclosed EXCO Resources Marcellus Undisclosed Marcellus Atlas Energy Marcellus Chesapeake Energy Marcellus Dominion Resources Marcellus Undisclosed Marcellus Anadarko Marcellus Epsilon Energy Marcellus NCL Appalachian Partners Marcellus Triad Energy Marcellus Wyoming County Landowners Group Marcellus Friendsville Group Marcellus Epsilon Energy Marcellus Chief Oil & Gas Marcellus Rex Energy Marcellus East Resources Marcellus Chesapeake Energy Marcellus Avista Capital Partners Marcellus Dominion Resources Marcellus Linn Energy Marcellus Mean JV Median JV
24
Source: John S. Herold, Inc. Mean M&A (1) Acreage represents Reliance JV AMI acreage only. Excludes Laurel Mountain and AHD value. Median M&A $900mm of value allocated to proved reserves and hedges, 105,000 Utica / Collingwood acres values at $1,000 / acre, 144,000 non-Marcellus JV acres valued at $2,000 / acre. (2) Value allocated assuming $8,000 / Mcfe/d of production and $250 / acre for non-Marcellus acreage (3) Value allocated to existing production at $10,000 / Mcfe/d (4) Value allocated to existing production at $8,000 / Mcfe/d (5) Value allocated to existing production at $5,667 / Mcfe/d (6) Value allocated to existing production at $14,000 / Mcfe/d
Total Value ($ MM) $405.0 3,703.0 850.0 70.0 140.0 27.0 392.0 4,700.0 19.5 950.0 191.9 1,700.0 253.0 3,475.0 280.0 1,400.0 100.0 400.0 81.0 212.8 192.0 12.7 406.0 33.0 350.0 3,375.0 71.5 347.0 600.0
Net Acreage 50,000 342,000 500,000 17,100 15,555 3,800 62,600 650,000 10,000 93,000 42,344 120,000 59,000 491,393 58,000 100,000 5,750 80,000 47,000 37,000 35,000 3,734 116,000 22,000 650,000 585,000 77,500 114,259 152,000
$ / Acre $8,100 7,084 1,700 (1) 4,094 9,000 7,105 6,262 6,385 1,950 (2) 8,073 4,532 14,167 4,288 (3) 4,797 4,828 14,000 (4) 10,530 5,000 1,000 (5) 5,751 5,486 3,401 3,500 1,500 538 5,769 923 3,037 (6) 1,645 $6,696 6,016 $4,047 4,797
Drivers of Value Good Oil & Gas Property = Good Real Estate
Good Rock
Attractive Location
Low Costs
High Oil or Gas-in-place
Relative supply and demand for the commodity
Shallow reservoir = lower cost drilling
Quality hydrocarbon – Rockies vs. Appalachia Ability of the hydrocarbon to flow through rock (permeability) Some rock tougher to drill
Proximity to Transportation Infrastructure Friendly operating environment
Low operating costs – Low water cut – Infrastructure in place (roads, electricity, etc) Fiscal regime
– Alaska vs. West Texas
25
3. Understanding the Upstream P&L
Land and Leasing Issues E&P companies rarely own the land on which they drill, but instead will lease mineral rights – Usually, the lessor (owner) receives an upfront cash payment (bonus payment) in addition to a percentage of the oil and gas revenue generated by the lease (royalty) – Royalties in the Lower 48 typically range from 12.5% to 25%, but terms are negotiated, and vary widely A typical lease gives a company (lessee) a period of three to five years to generate commercial production on the lease – Once commercial production is established, a lease is said to be held-by-production (HBP) – If no production is established, the expires – Future lease expirations often have a substantial impact on a company’s drilling plans as companies will plan drilling programs to lock up acreage that expires in the near-term – Large, contiguous blocks of acreage are preferred as they provide operators with greater flexibility in locking up acreage Leasing terms from the federal government tend to be more favorable due to longer lease terms – More common in the Rockies
26
Operating Drivers Revenue = Price * Quantity
Expenses
Gross (Wellhead) Production
Production Taxes, which include:
Less: royalties
Severance Taxes (Percent of Revenue)
Net Production
Ad Valorem Taxes (Percent of Revenue, but net of Severance)
Note: Production generally shown in daily terms Lease Operating Costs (fixed and variable components, sometimes
Benchmark (NYMEX) Prices
simplified to a $ per Mcfe or Boe basis)
Less: Basis Less / Plus: Quality differences Less: Transportation Costs = Realized Prices
SG&A (generally a fixed cost) Differential
Exploration Costs, depending on whether a company chooses full cost or successful efforts accounting – Added back to calculate EBITDAX for comparability purposes DD&A – calculation is complex
27
Calculating Production Current Production Net wells = gross wells * average working interest (W.I.) – Gross: wells in which you own an interest – Working interest: percent that you own – Note: all company-level disclosure is generally on a net basis Production = net wells * average net production per well Net production per well = wellhead production less royalties Future Production Remaining drilling inventory (locations)= risked acreage / well spacing Production = type curve * wells drilled Risked acreage = total acreage * risk rate Wells drilled per year = rigs operating * (365 / spud-to-spud)
28
Illustrative Horizontal Well Bore Schematic Denson 2H-15 Denson 2H-15 200' FSL & 300' FWL Sec 10-1N-10E Coal Oklahoma 9 5/8", 36#, J-55 csg
688' GL, 710' KB December 1, 2009
Set @ 295' Cmt w/ 210 sxs.
Cmt top @ 6150'
KOP @ 7440' 5 1/2" P-110, 17# csg set @ 13057' Cmt w/ 880 sxs
LP @ 8360' (81.68 deg - 8012' TVD)
TD @13057' 90.57 deg 7838' TVD
PBD @ 13000' Top of
8270'
8700'
9110'
9496'
10040'
10470'
10910'
11355'
11790'
12230'
12670'
4' perf guns 6 jspf 96 holes/stg
8370' 8470' 8570'
8800' 8900' 8990'
9190' 9280' 9380'
9540' 9590' 9640'
10130' 10230' 10330'
10565' 10675' 10770'
11010' 11110' 11200'
11450' 11550' 11650'
11890' 11990' 12090'
12330' 12430' 12530'
12810' 12950'
9690' 9740' 9790' 9885'
29
Illustrative 80-Acre Horizontal Well Spacing 175’
175’
#2
#3
#4
#5
#7
#8
4930’ Laterals
5280’
330’
660’
660’
175’
175’
660’ x 7 + (330’ + 330’) = 5,280’
1 section = 640 acres, or 1 square mile 30
#6
4930’ Laterals
#1
330’
Realizing Pricing Subject to Many Issues
Commodity Benchmark Pricing
Differentials
Transportation WTI Realized Pricing
Quality Quality Brent
Location Henry Hub
Location
31
New Pipeline Capacity Has Reduced Woodford Basis $14.00
A
Fall ’08 Financial Crisis
B
C
D
$12.00
$ / MMBtu
$10.00
$8.00
$6.00
$4.00
$2.00
$0.00 Jan-08
Jul-08 Centerpoint East
Jan-09 Panhandle East
A: REX West Pipeline goes into service. B: Texas Gulf Crossing Pipeline goes into service.
32
Jul-09
Jan-10
Jul-10
Henry Hub
C: Midcontinental Express Pipeline goes into service. D: REX East Pipeline goes into service.
Accounting Discussion E&P companies may choose from two different accounting methods for exploration and dry well expenses: full cost or successful efforts.
Full Cost
Successful Efforts
Capitalize all costs associated with drilling, including dry hole and G&G and G&A costs
Capitalize only costs of successful wells
Higher carrying value of PP&E Generally, higher earnings than Successful Efforts from lower expense associated with dry holes In theory, identical cash from operations relative to Successful Efforts Preference of smaller companies with more volatile earnings More stringent ceiling test required to avoid build up of unrecovered costs – Carrying value compared to after-tax, pre-G&A PV-10 of cash flow
33
Expense of dry hole and G&G and G&A costs as incurred Lower carrying value of PP&E Generally, lower earnings than Full Cost from higher expense associated with dry holes In theory, identical cash from operations relative to Full Cost Preference of larger companies Unusual to book asset impairments due to regular expensing of unsuccessful efforts – Carrying value compared to pre-tax, pre-G&A, undiscounted value of cash flow
4. E&P Ratio Analysis
Reserve Replacement Cost and Rate Pioneer Natural Resources Company Reserve Replacement Costs per boe (RRC) are computed by taking total costs incurred (proved and unproved property acquisition costs, exploration costs and development costs) during the applicable period as the numerator and dividing by the total oil equivalent reserve changes associated with discoveries and extensions, revisions in estimates, improved recovery and purchase of proved reserves in place as the denominator Reserve Replacement Rates are computed by dividing production for the period into the total reserve changes for the period used in the denominator for computing RRC reduced by volumes sold during the period Pioneer Nat Res Summary Worldwide Capital Efficiencies Measures (1) All Sources (a) Reserve Replacement Cost Total Costs Incurred (US$ MM) Net Reserves Added (MMBOE) Extensions and discoveries Improved recovery Revisions of previous estimates Purchase of reserves in place Total Net Reserves Added (MMBOE) Reserve Replacement Cost (US$ / BOE) JS Herold Other Source
34
7
$
$ $
5 Worldwide
3 United States
1 Year 3 Years 5 Years 2000 1998-00 1996-00 340 $ 1,004 $ 5,460 38.0 27.5 7.4 72.9 4.66 4.66 NA
$ $
59.2 70.7 14.7 144.6 6.94 6.94 NA
$ $
66.6 191.3 474.6 732.5 7.45 7.45 NA
$
$ $
1 Year 3 Years 5 Years 2000 1998-00 1996-00 204 $ 640 $ 3,908 15.9 29.9 5.9 51.8 3.94 3.94 NA
$ $
17.0 74.8 5.9 97.8 6.55 6.55 NA
$ $
23.1 195.9 320.7 539.8 7.24 7.24 NA
(b) Reserve Replacement Rate I Total net reserves added (MMBOE) Production (MMBOE) Reserve Replacement Rate (%)
72.9 43.6 167%
144.6 157.5 92%
732.5 216.8 338%
51.8 30.9 168%
97.8 117.0 84%
539.8 175.4 308%
(c) Reserve Replacement Rate II Reserves Added Less Sales (MMBOE) Total net reserves added (MMBOE) Less: sales of reserves in place Total Reserves Added Less Sales (MMBOE) Production (MMBOE) Reserve Replacement Rate (%) JS Herold Other Source
72.9 (6.6) 66.3 43.6 152% NA NA
144.6 (120.5) 24.1 157.5 15% NA NA
732.5 (184.3) 548.2 216.8 253% NA NA
51.8 (6.6) 45.2 30.9 146% 146% NA
97.8 (104.1) (6.3) 117.0 (5%) NA NA
539.8 (136.5) 403.3 175.4 230% 230% NA
F&D Cost and Rate Pioneer Natural Resources Company Finding and Development Costs per boe (FDC) are computed by taking as the numerator total costs incurred less costs of proved property acquisitions and dividing by a denominator comprised of the total oil equivalent reserve changes for the period associated with discoveries and extensions, revisions in estimates and improved recoveries (costs associated with proved property purchases are excluded) Finding and Development Replacement Rates are computed by dividing production for the period into the total reserve changes associated with discoveries and extensions, revisions in estimates and improved recoveries Pioneer Nat Res Summary Worldwide (2) Finding & Development (d) Finding & Development Costs Costs Incurred (US$ MM) Unproved property acquisition Exploration Development Costs Incurred (US$ MM) Reserves Added (MMBOE) Extensions and discoveries Improved recovery Revisions of previous estimates Reserves Added (MMBOE) Finding & Development Cost (US$ / BOE) JS Herold Other Source (e) Reserve Replacement Rate Reserves Added (MMBOE) Production (MMBOE) Reserve Replacement Rate (%) JS Herold Other Source (3) Finding & Development (No Revisions) (f) Finding & Development Costs Costs Incurred (US$ MM) Reserves Added (MMBOE) Extensions and discoveries Improved recovery Reserves Added (MMBOE) Finding & Development Cost (US$ / BOE) (g) Reserve Replacement Rate Reserves Added (MMBOE) Production (MMBOE) Reserve Replacement Rate (%)
35
2000 $ $
$ $
31 131 142 304 38.0 27.5 65.5 4.64 4.64 NA
Worldwide 1998-00 $ $
$ $
65.5 43.6 150% 150% NA
37 323 544 905 59.2 70.7 129.9 6.97 6.97 NA
1996-00 $ $
$ $
129.9 157.5 82% 82% NA
581 458 965 2,003 66.6 191.3 257.9 7.77 7.77 NA
$
$
38.0 38.0 7.99 38.0 43.6 87%
$
59.2 157.5 38%
$ $
$ $
257.9 216.8 119% 119% NA
Worldwide 2000 1998-00 1996-00 304 $ 905 $ 2,003 59.2 59.2 15.29
2000
$
66.6 66.6 30.07 66.6 216.8 31%
United States 1998-00
28 65 85 178 15.9 29.9 45.8 3.88 3.88 NA
$ $
$ $
45.8 30.9 149% 149% NA
$
$
65 170 358 594 17.0 74.8 91.9 6.46 6.46 NA
1996-00 $ $
$ $
91.9 117.0 79% 79% NA
162 290 770 1,222 23.1 195.9 219.0 5.58 5.58 NA 219.0 175.4 125% 125% NA
United States 2000 1998-00 1996-00 178 $ 594 $ 1,222 15.9 15.9 11.20 15.9 30.9 52%
$
17.0 17.0 34.85 17.0 117.0 15%
$
23.1 23.1 52.88 23.1 175.4 13%
E&P Capital Efficiency Data Pioneer Natural Resources Company
Pioneer Nat Res Summary Worldwide (4) Exploration and Development (h) Finding & Development Costs Costs Incurred (US$ MM) Exploration Development Costs Incurred (US$ MM) Reserves Added (MMBOE) Finding & Development Cost (US$ / BOE)
2000
$ $
(i) Reserve Replacement Rate Reserves Added (MMBOE) Production (MMBOE) Reserve Replacement Rate (%) (5) Proved Reserve Acquisitions (j) Proved Reserve Replacement Cost Cost of proved property acquisition ($ MM) Reserves added through proved acq (MMBOE) Proved Reserve Replacement Cost (US$ / BOE) (k) Reserve Replacement Rate Reserves added through proved acq (MMBOE) Production (MMBOE) Reserve Replacement Rate (%)
36
$ $
Worldwide 1998-00
1996-00
131 142 273 $ 38.0 7.17 $
323 544 868 $ 59.2 14.66 $
458 965 1,423 66.6 21.36
38.0 43.6 87%
59.2 157.5 38%
66.6 216.8 31%
Worldwide 2000 1998-00 1996-00 36 $ 99 $ 3,457 7.4 14.7 474.6 4.90 $ 6.73 $ 7.28 7.4 43.6 17%
14.7 157.5 9%
474.6 216.8 219%
2000
$ $
$ $
United States 1998-00
1996-00
65 85 150 $ 15.9 9.42 $
170 358 528 $ 17.0 31.01 $
290 770 1,060 23.1 45.87
15.9 30.9 52%
17.0 117.0 15%
23.1 175.4 13%
United States 2000 1998-00 1996-00 26 $ 47 $ 2,686 5.9 5.9 320.7 4.41 $ 7.89 $ 8.38 5.9 30.9 19%
5.9 117.0 5%
320.7 175.4 183%
Per Barrel Income and Cash Flow Anadarko Petroleum Corporation Oil and gas differentials Realized oil and gas revenue per BOE Lease operating expense per BOE Cash netback per BOE Oil and Gas Disclosure: Select Income, Cash Flow and Operating Data
1998A
1999A
FYE Dec 31 2000A
Oil and Gas Disclosure: Per Barrel Economics (US$ / BOE)
1997
1999
2000
Total Production Liquids (MMBBL) Gas (BCF) Oil Equivalent (MMBOE 6:1)
1998A
14.5 179.0 44.3
17.8 177.0 47.3
21.1 170.0 49.4
47.0 385.0 111.2
Blended Benchmark Commodity Price (1) Oil and Gas Blended Differential Realized Oil and Gas Revenue
16.76 (2.00) 14.76
13.20 (1.84) 11.37
16.04 (2.15) 13.89
27.72 (2.51) 25.21
Average Realized Commodity Prices Liquids (US$ / BBL) Natural Gas (US$ / MCF)
16.76 2.30
11.05 1.92
15.76 2.08
25.29 4.13
Average Benchmark Commodity Prices WTI oil spot (US$ / BBL) Henry Hub gas spot (US$ / MCF)
Lease Operating Expenses General and Administrative Cash Netback (i.e., EBITDAX)
(3.56) 0.00 11.20
(3.66) 0.00 7.70
(3.23) 0.00 10.66
(5.17) 0.00 20.04
20.58 2.48
14.38 2.08
19.30 2.27
30.37 4.30
Oil and Gas DD&A Oil and Gas Operating Income (EBIT)
(4.09) 7.11
(3.88) 3.82
(3.97) 6.70
(5.13) 14.91
Commodity Differentials Liquids (US$ / BBL) Natural Gas (US$ / MCF)
(3.83) (0.18)
(3.33) (0.16)
(3.54) (0.19)
(5.07) (0.17)
Oil and Gas Income Taxes Oil and Gas Net Income (NOPAT)
(2.52) 4.59
(1.37) 2.45
(2.83) 3.87
(5.78) 9.13
Oil and Gas Revenues (US$ MM) Liquids sales Gas sales Total Oil and Gas Revenues
7.59
6.24
6.46
9.28
242.6 411.7 654.29
197.8 339.8 537.6
333.0 353.6 686.6
1,213.0 1,590.1 2,803.0
Oil and Gas Costs and Expenses (US$ MM) Production costs (incl. prod taxes) Other operating costs General and administrative Exploration expense Impairment costs Book DD&A Total Oil and Gas Costs and Expenses
(157.8) 0.0 0.0 0.0 0.0 (181.2) (339.0)
(173.2) 0.0 0.0 0.0 0.0 (183.6) (356.8)
(159.5) 0.0 0.0 0.0 0.0 (196.2) (355.7)
(575.0) 0.0 0.0 0.0 0.0 (570.0) (1,145.0) 1,658.0
Oil and Gas Analyst Cash Flow
315.3
180.8
331.0
Oil and Gas Income Taxes
(US$ MM)
(111.7)
(64.8)
(139.7)
Oil and Gas Net Inc (NOPAT)
(US$ MM)
203.6
116.0
191.3
1,015.0
496.4
364.4
527.2
2,228.0
FYE Dec 31 1997A
1998A
1999A
FYE Dec 31 2000A
203.6 181.2 0.0 (48.3) 336.5
116.0 183.6 0.0 (4.5) 295.1
191.3 196.2 0.0 (68.1) 319.4
1,015.0 570.0 0.0 (553.7) 1,031.3
(55.6) (231.1) (363.7) (650.4)
(177.3) (305.2) (377.2) (859.7)
(92.9) (206.7) (353.5) (653.1)
(7,047.0) (415.0) (1,054.0) (8,516.0)
Note: Oil and Gas EBITDAX (US$ MM) Oil and Gas Disclosure: Select Income, Cash Flow and Operating Data (cont'd) (US$ MM) Oil and Gas Analyst Cash Flow Net Income DD&A Exploration Expense + Impairment Deferred Taxes Oil and Gas Analyst Cash Flow Oil and Gas Capital Expenditures Acquisitions Exploration Development Total Oil and Gas Capital Expenditures Approximate Oil and Gas Free Cash Flow Source of data
(643.0)
(314.0)
(564.6)
(333.7)
(7,484.7)
12/97 10-K
12/98 10-K
12/99 10-K
12/00 10-K
FYE Dec 31 1997A
1998
FYE Dec 31 1999A 2000A
Oil and Gas Earnings B4 Int & Tax (EBIT)
37
FYE Dec 31 1997A
(1) Based on WTI oil and Henry Hub natural gas spot prices using co's actual production mix in given year
Full-Cycle Economic Costs Landscape of E&P Costs Full-cycle costs are the total capital and operating costs of producing oil Full cycle costs are sum of – Reserve replacement cost – + Production cost Full cycle costs generally exclude G&A, interest and transportation costs A company’s full cycle costs are very much tied to the region(s) in which it operates
U .S . L a rg e -C a p E x p lo ra tio n a n d P ro d u c tio n S e c to r Y e a r 2 0 0 0 F u ll C yc le E c o n o m ic s ($ /B O E ) 3 -Y r A ll S o u rc e s 2000 L ease 2000 F u ll-C yc le R e s e rv e R e p la c e O p e ra tin g G &A E c o n o m ic m e n t C o s ts E xpen ses C o st C o s ts
(6 M C F / B b l)
H is to ric a l F u ll C yc le E c o n o m ic s ($ /B O E )
2000
1999
1998
3 -Y r A v e r a g e (1 9 9 8 -0 0 )
B u rlin g to n
5 .8 0
7 .1 6
0 .0 0
1 2 .9 6
1 2 .9 6
1 1 .1 1
1 1 .4 2
1 1 .8 3
O c e a n E n e rg y
6 .0 8
5 .1 8
0 .0 0
1 1 .2 7
1 1 .2 7
1 1 .0 0
1 2 .4 3
1 1 .5 6
K e rr-M c G e e
5 .5 9
5 .8 4
0 .0 0
1 1 .4 3
1 1 .4 3
1 0 .9 8
1 3 .3 3
1 1 .9 1
P io n e e r N a t R e s
6 .9 4
5 .8 9
0 .0 0
1 2 .8 3
1 2 .8 3
1 2 .1 6
1 2 .8 4
1 2 .6 1
D e v o n E n e rg y
6 .5 7
4 .9 4
0 .0 0
1 1 .5 0
1 1 .5 0
9 .2 9
9 .6 3
1 0 .1 4
X T O E n e rg y
3 .8 1
5 .2 6
0 .0 0
9 .0 7
9 .0 7
8 .8 3
8 .7 8
8 .8 9
A n a d a rk o P e tro le u m
6 .3 0
5 .1 7
0 .0 0
1 1 .4 7
1 1 .4 7
7 .0 8
7 .0 2
8 .5 3
U n o c a l C o rp .
7 .1 0
3 .8 2
0 .0 0
1 0 .9 2
1 0 .9 2
1 0 .5 3
1 1 .4 3
1 0 .9 6
N o b le A ffilia te s
7 .6 5
4 .3 1
0 .0 0
1 1 .9 6
1 1 .9 6
9 .1 9
1 0 .9 4
1 0 .7 0
A p a c h e C o rp .
5 .6 1
3 .2 3
0 .0 0
8 .8 4
8 .8 4
8 .5 5
8 .9 2
8 .7 7
E O G R e s o u rc e s
5 .8 7
3 .2 5
0 .0 0
9 .1 1
9 .1 1
7 .5 5
5 .6 8
7 .4 5
M ean
$
6 .1 2
$
4 .9 1
$
-
$
1 1 .0 3
$
1 1 .0 3
$
9 .6 6
$
1 0 .2 2
$
1 0 .3 0
M e d ia n
$
6 .0 8
$
5 .1 7
$
-
$
1 1 .4 3
$
1 1 .4 3
$
9 .2 9
$
1 0 .9 4
$
1 0 .7 0
The Full-Cycle Cost of Oil ($/Bbl) Regional Basis
38
Iraq
2.50
Other Latin America
5.52
Kazakhstan
7.00
Western Canada
9.25
Kuwait
3.80
Alaska
5.70
Mexico
7.20
North Sea
9.85
Saudi Arabia
4.00
Nigeria
5.75
US Lower 48
8.10
Indonesia
10.50
Venezuela
4.23
Oman
6.25
China-Onshore
8.90
China Offshore
11.80
Iran
4.50
Algeria
7.00
Angola
9.00
Brazil
12.50
Abu Dhabi
5.00
Western Siberia
7.00
US GOM
9.00
US Stripper Wells
15.17
Economics of the Large Cap E&P Sector Full-Cycle Costs, ROCE’s and Commodity Prices Full-Cycle Costs ($/bbl) Reserve Replacement $6.50 Operating Cost3.57 Full-Cycle Cost$10.07
Cash Break-Even WTI Price ($/bbl) Full-Cycle Cost$10.07 Gen. & Admin. 1.00 Differential to WTI2.28 Break-Even WTI$13.35
At current costs and $18.50 oil prices, the large cap companies exactly earn their cost of capital E&P companies have found it devilishly hard to return their cost of capital – Capital-intensive business – Historical lack of capital discipline – Dependent on commodity prices, which can fluctuate wildly – Best opportunity set available to majors, not independent E&P’s 39
Returns and Full-Cycle Economics(1)(2) Return on Capital Employed (%) 20
(%)
$24.00 Oil
18.7%
$22.00 Oil
15.1%
18
16
14
12
$19.72 Oil (10-yr Average WTI Price [1990-99])
10
8
11.2%
$18.50 Oil
9.0%
$18.00 Oil
8.1%
$16.00 Oil
4.6%
$14.00 Oil
1.1%
9.0% Large Cap E&P Cost of Capital
6
4
2
0 $3
$5
$7
$9
$11
Full-Cycle Economics ($/boe) (Reserve Replacement Cost + Operating Cost [$/boe]) Notes 1. Returns calculated on replacement cost basis: ROCE equals NOPAT/replacement cost capital where (a) NOPAT equals EBITDAX less replacement cost of production less cash taxes, and (b) replacement cost capital equals beginning proved reserves times historical (then 3-year average) reserve replacement cost 2. Large cap E&P sector full-cycle economics of $10.07/bbl as per JS Herold, which breaks down as $6.50/bbl for reserve replacement cost plus $3.57/bbl for operating cost. Additionally, to calculate returns, $1.00/bbl for general and administrative costs are added to the full-cycle costs and $2.28/bbl for the average differential to WTI oil is subtracted from the WTI price
$13
Calculating ROCE’s in the E&P Sector So Many Choices, So Little Time...
EVAAnalysis (US$ MM) Net Operating Profit After Tax (NOPAT) Recurring EBIT (B4 Expl Expense) Other Recurring Cash Income Less: Cash Taxes (Unlevered) NOPAT Cash Taxes (Unlevered) Cash Taxes (Levered) Addback: Tax Savings fromInterest (35.0%) Cash Taxes (Unlevered)
1998A
1999A
FYEDec 31 2000A
124.3 23.2 (26.4) 121.1
59.2 55.6 (66.1) 48.7
201.2 88.8 (70.5) 219.5
406.5 39.8 (61.3) 385.0
(a) Reported NOPAT Operating EBIT (B4 Expl Expense) Less: Unlevered Cash Taxes NOPAT (After-Tax EBIT)
(8.6) (57.5) (66.1)
(10.8) (59.6) (70.5)
(4.6) (56.7) (61.3)
Net Capital Expenditures Total Gross Cap Expenditures Other Sources / Uses of Cash Proceeds fromAsset Sales Less: DD&A(proxy for Maintenance Capex) Net Capital Expenditures
(456.9) 0.0 115.7 212.4 (128.7)
(538.9) 0.0 21.9 337.3 (179.7)
(191.5) 0.0 390.5 236.0 435.0
(299.7) 2.4 102.7 214.9 20.4
Net New Investment Net Capital Expenditures Investment in Net Working Capital Net NewInvestment
(128.7) (39.3) (168.0)
(179.7) 86.0 (93.7)
435.0 (49.6) 385.5
20.4 (44.0) (23.6)
35%
Correct
Invested Capital Invested Capital: Beginning Addition: Net NewInvestment Invested Capital: Ending
ROIC(NOPAT / Beginning Invested Capital) Economic Profit (ROIC- WACC) * IC
40
1998A
1999A
FYE Dec 31 2000A
121.1 (168.0) (47.0)
48.7 (93.7) (45.0)
219.5 385.5 605.0
385.0 (23.6) 361.5
(0.0)
0.0
0.0
0.0
Howabout purchase accounting adjustments?
----3,498.4 8.0%
3,498.4 93.7 3,592.0
3,592.0 (385.5) 3,206.6
3,206.6 23.6 3,230.1
280 (231)
287 (68)
257 128
1.4% (231)
6.1% (68)
12.0% 128
124 (26) 98
59 (66) (7)
201 (70) 131
407 (61) 345
(b) Capital Employed (Historical Cost) Total Debt Less: Cash Minority Interest Preferred Stock at Book Value Common Equity at Book Value Capital Employed
1,950 (73) 0 0 1,549 3,425
2,175 (59) 0 0 789 2,905
1,746 (35) 0 0 775 2,486
1,579 (26) 0 0 905 2,458
(c) ROCE I Reported NOPAT Capital Employed, beginning ROCE
98 3,425 2.9%
(7) 3,425 (0.2%)
131 2,905 4.5%
345 2,486 13.9%
(2) ROCE II (a) Reported NOPAT Operating EBIT (B4 Expl Expense) Less: Unlevered Cash Taxes NOPAT (After-Tax EBIT)
124 (26) 98
(b) Capital Employed (EVA Method) Invested Capital: Beginning Addition: Net New Investment Invested Capital: Ending
----3,498
3,498 94 3,592
3,592 (385) 3,207
3,207 24 3,230
(c) ROCE II Reported NOPAT Capital Employed, beginning ROCE
98 3,498 2.8%
(7) 3,498 (0.2%)
131 3,592 3.6%
345 3,207 10.8%
FYE Dec 31 1997A
1998A
1999A
FYE Dec 31 2000A
Pioneer Nat Res Returns on Capital Employed (ROCE) (US$ MM)
59 (66) (7)
201 (70) 131
407 (61) 345
(3) ROCE III This ROCE is like (1) above except that NOPAT is adjusted to have uniform tax rate (across this and other companies)
(a) Tax-Adjusted NOPAT Operating EBIT (B4 Expl Expense) Less: Assumed Taxes (35%) NOPAT (After-Tax EBIT)
FYE Dec 31 1997A
1998A
1999A
FYE Dec 31 2000A
(4) ROCE IV This ROCE is like (3) above except that it keeps running tally of invested capital using EVA framework
This ROCE is like (1) above except that it keeps running tally of invested capital using EVA framework
Unlevered Free Cash Flow NOPAT Less: Net NewInvestment Unlevered Free Cash Flow
Economic Profit Capital charge (WACC[8.0%] * IC) Economic profit (NOPAT - Cap charge)
FYE Dec 31 1997A
(1) ROCE I This is traditional ROCE: uses actual cash taxes and capital at historical cost from balance sheet
0.7 (27.1) (26.4)
Check (Two Free Cash Flows equal [=0?])
Pioneer Nat Res ROCE Calculations (US$ MM)
FYEDec 31 1997A
124 (44) 81
59 (21) 38
201 (70) 131
407 (142) 264
(b) Capital Employed (Historical Cost) Total Debt Less: Cash Minority Interest Preferred Stock at Book Value Common Equity at Book Value Capital Employed
1,950 (73) 0 0 1,549 3,425
2,175 (59) 0 0 789 2,905
1,746 (35) 0 0 775 2,486
1,579 (26) 0 0 905 2,458
(c) ROCE III Tax-Adjusted NOPAT Capital Employed, beginning ROCE
81 3,425 2.4%
38 3,425 1.1%
131 2,905 4.5%
264 2,486 10.6%
35%
(a) Tax-Adjusted NOPAT Operating EBIT (B4 Expl Expense) Less: Assumed Taxes (35%) NOPAT (After-Tax EBIT)
35%
124 (44) 81
59 (21) 38
201 (70) 131
407 (142) 264
(b) Capital Employed (EVA Method) Invested Capital: Beginning Addition: Net New Investment Invested Capital: Ending
----3,498
3,498 94 3,592
3,592 (385) 3,207
3,207 24 3,230
(c) ROCE IV Tax-Adjusted NOPAT Capital Employed, beginning ROCE
81 3,498 2.3%
38 3,498 1.1%
131 3,592 3.6%
264 3,207 8.2%
FYE Dec 31 1997A
1998A
1999A
FYE Dec 31 2000A
Pioneer Nat Res Returns on Capital Employed (ROCE) (US$ MM) (5) ROCE V
This is meant to be best economic ROCE measure for an E&P company; accounting-warped DD&A is replaced with economic cost of generating associated EBITDAX (i.e., production times reserve replacement cost); actual taxes are used; and accounting-capital is replaced w/ economic cost of replacing capital
(a) Normalized NOPAT EBITDAX Less: Replacement Cost of Production Less: Unlevered Cash Taxes Normalized NOPAT
337 (249) (26) 61
397 (544) (66) (214)
437 (427) (70) (60)
621 (302) (61) 258
(b) Replacement Cost Capital Proved Reserves Bgn Yr (MMBOE 6:1) 3-Yr Avg Reserve Repl Cost ($/BOE) Replacement Cost of Reserves Net Working Capital and Other Assets Replacement Cost Capital
302 7.04 2,127 (91) 2,036
762 8.65 6,590 (129) 6,461
677 8.36 5,659 (17) 5,641
605 6.94 4,203 (57) 4,146
(c) ROCE V Normalized NOPAT Replacement Cost Capital ROCE
61 2,036 3.0%
(214) 6,461 (3.3%)
(60) 5,641 (1.1%)
258 4,146 6.2%
35.4 7.04 249
62.9 8.65 544
51.1 8.36 427
43.6 6.94 302
1998A
1999A
(d) Replacement Cost of Production Production in Year (MMBOE 6:1) 3-Yr Avg Reserve Repl Cost ($/BOE) Replacement Cost of Production Pioneer Nat Res Returns on Capital Employed (ROCE) (US$ MM)
FYE Dec 31 1997A
FYE Dec 31 2000A
(6) ROCE VI This ROCE is like (5) above except that NOPAT is adjusted to have uniform tax rate (across all companies)
(a) Tax-Adjusted Normalized NOPAT EBITDAX Less: Replacement Cost of Production Less: Assumed Taxes (35%) 35% Tax-Adjusted Normalized NOPAT (b) Replacement Cost Capital Proved Reserves Bgn Yr (MMBOE 6:1) 3-Yr Avg Reserve Repl Cost ($/BOE) Replacement Cost of Reserves Net Working Capital and Other Assets Replacement Cost Capital (c) ROCE VI Tax-Adjusted Normalized NOPAT
337 (249) (31) 57
397 (544) 52 (96)
437 (427) (4) 7
621 (302) (112) 207
302 7.04 2,127 (91) 2,036
762 8.65 6,590 (129) 6,461
677 8.36 5,659 (17) 5,641
605 6.94 4,203 (57) 4,146
57
(96)
7
207
5. Glossary
Glossary of Key Petroleum Terms Abandon – To discontinue attempts to produce oil or gas from a well or lease and to plug the reservoir in accordance with regulatory requirements. AFE (Authority for Expenditure) – A form used during the planning process for a well about to be drilled. It includes an estimate of costs to be incurred in the IDC category and in the tangible equipment category. The form represents a budget for the project against which actual expenditures are compared. Associated gas – Natural gas, occurring in the form of a gas cap, overlying an oil zone. Behind Pipe – Reserves expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to the start of production. Bonus – The consideration paid by the lessee to the lessor upon execution of an oil and gas lease. Carried interest – An agreement under which one party (carrying party) agrees to pay for a portion or for all of the development and operating costs of another party (carried party) on a property in which both own a portion of the working interest. The carrying party is able to recover a specified amount of costs from the carried party’s share of the revenue from production, if any, from the property. Christmas tree – A term applied to the valves and fittings assembled at the top of a well to control the flow of oil. Completion – Refers to the work performed and the installation of permanent equipment for the production of oil or gas from a recently drilled well. Condensate – A light hydrocarbon liquid which is in a gaseous state in the reservoir but which becomes liquid at the surface. Conveyance – The assignment or transfer of mineral rights to another person. Cost center – The geological, geographical, or legal unit with which costs and revenues are identified and accumulated. Examples are the lease, the field, and the country. Depletion – Amortization of capitalized costs of a mineral property. The deduction is based upon minerals produced. For Federal income tax purposes depletion may be based on the amount of gross income from the property.
41
Glossary of Key Petroleum Terms (Cont’d) Development well – A well drilled to gain access to oil or gas classified as “proved reserves.” Dry hole – An exploratory or development well that does not produce oil or gas in commercial quantities. Estimated Ultimate Recovery (EUR) – The amount of oil and gas expected to be economically recovered from a reservoir or field by the end of its producing life. Estimated ultimate recovery can be referenced to a well, a field, or a basin. Exploration well – All wells drilled to search for or produce oil or gas, except development wells and development-type stratigraphic test wells drilled to gain access to proved reserves. Farm-out – Transfer of all or part of the operating rights from the working interest owner to an assignee, who assumes all or some of the burden of development, for an interest in the property. The assignor usually retains an overriding royalty but may retain any type of interest. Field – An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geologic structural feature and/or stratigraphic feature. Fluid injection – Inducing gas or liquids into a reservoir to move oil toward the well bore. Fracturing / Fracing – A procedure to stimulate production by forcing under high pressure a mixture of oil ad sand into the formation. Gravity – A standard API gravity scale which is related to specific gravity of a petroleum fluid based on a technical formula. Held-by-production (BHP) – A provision in an oil, gas and mineral lease that perpetuates a company’s right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or gas. Also abbreviated as HBP.
42
Glossary of Key Petroleum Terms (Cont’d) IDC (Intangible Drilling Cost) – Any cost which in itself has no salvage value and is necessary for and incident to the drilling of wells and getting them ready for production. IDC can also occur when deepening or plugging back a previously drilled oil or gas well, or an abandoned well, to a different formation. IDCs are expensed for tax purposes, which result in companies that actively drill having a very low tax liability. IP (Initial Production) – The measurement of a well's production at the outset. Often measured either over 24 hours or 30-days. Lease – (1) A contract in which the owner of minerals gives an oil company the right to explore for, develop, and produce minerals from the property. (2) Any transfer where the owner of a mineral interest assigns all or part of the operating rights to another party but retains a continuing non-operating interest in production from the property. Lifting costs – Costs of operating wells for the production of oil and gas (producing costs), loosely analogous to LOE, or Lease operating costs Net profits interest (NPI) – An interest in production created from the working interest and measured by a certain percentage of the net profits (as defined in the contract) from the operation of the property. Non-operating interest – An interest in minerals. The holder of this interest does not have the responsibility or bear the cost of developing and producing the minerals. Net revenue interest (NRI) – A share of production after all burdens, such as royalty and overriding royalty, have been deducted from the working interest. It is the percentage of production that each party actually receives. Offset well – Well drilled on one tract of land to prevent drainage of oil or gas to a nearby tract on which a well has been drilled. Operator – Organization that obtains (buys or leases) the right to drill and produce oil and/or natural gas from the owner of a specified location. The operator of an oil or gas well or field.
43
Glossary of Key Petroleum Terms (Cont’d) Overriding royalty (ORRI) – A royalty interest that is created out of the operating interest. Its term is coextensive with that of the operating interest from which it was created. Percentage depletion – A deduction for Federal income tax purposes based on the gross income from mineral properties. Percentage depletion is in lieu of cost depletion. Also known as statutory depletion. Permeability – The measure of the ease with which oil can move through a reservoir. Plug back – To seal off a lower formation in a well bore in order to produce from a higher formation. Porosity – The relative volume of the pore space compared to the total bulk volume of the reservoir. Production taxes – Taxes levied by state governments on mineral production based on the value and/or quantity of production. Also called severance taxes. Proved developed reserves – Reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves – Quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be recoverable in the future from know oil and gas reserves under existing economic and operating conditions. Proved undeveloped reserves – Reserves which are expected to be recovered from new wells in undrilled proved acreage, or from existing wells where relatively major expenditures are required for completion. Regulatory spacing – The regulation of both the location and the number of wells which can be drilled into a common reservoir (for conservation purposed). Regulations established by an agency of a state or government. Reservoir – A porous, permeable, subsurface rock formation containing trapped oil, natural gas, or water.
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Glossary of Key Petroleum Terms (Cont’d) Revenue interest – The percentage of revenue received by a working interest after payment of royalties Rig – The derrick or mast, drawworks and attendant surface equipment of a drilling unit. Royalty – An interest in the oil and gas in place that entitles the holder to a specified fraction, in kind or in value, of the total production from the property, free of any expense of development and operation. The basic royalty interest is retained by the lessor of the oil/gas property in the original lease agreement. Secondary recovery – The use of such devices as water-flooding, gas-injection and other methods to recover oil beyond that which can by natural flowing or by pumping. Shut-in well – A producing well (more often on gas properties than oil properties) that has been closed down temporarily. Sidetrack – A secondary wellbore drilled away from the original hole. It is possible to have multiple sidetracks, each of which might be drilled for a different reason. A sidetracking operation may be done intentionally or may occur accidentally. Spud – To start the well drilling process by removing rock, dirt and other sedimentary material with the drill bit. To apply weight to a troublesome drilling section, usually by moving the drilling string up and down, in hopes that the section will drill faster. Stripper well – A well nearing the end of its productive life; very little oil is being produced. For certain tax applications, wells with less than 10 B/D of production. Take-or-pay contracts – An agreement in which a gas purchaser agrees to take a minimum quantity of gas per year if he is not prevented form doing so by circumstances beyond his control and if the gas is available for delivery. If the purchaser does not take the minimum quantity, he is required to pay for the minimum quantity at the contract price; normally, he may make up deficiency amounts in future years if he purchases in excess of minimum amounts. Tangible assets – The cost of assets that in themselves have a salvage value.
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Glossary of Key Petroleum Terms (Cont’d) Tertiary recovery – The use of sophisticated techniques such as flooding the reservoir with chemicals to increase the production of oil or gas. Unitization – An agreement under which two or more persons owning operating mineral properties agree to have the properties operating on a unified basis and further agree to share in production from all the properties on a stipulated percentage or fractional basis regardless of from which property the oil or gas is produced. All owners of economic interests in the properties should be involved in the agreement. Viscosity – The ability of a fluid to flow as a result of its physical characteristics. Waterflooding – A method of secondary recovery, in which water is injected into an oil reservoir for the purpose of washing the oil out of the reservoir rock and into the bore of a producing well. Well spacing – the space or acreage allocated to a well. The aerial extent that a well could drain (the volume) from a reservoir. It is a conservation measure that identifies the location and number of wells that can be drilled to drain a reservoir. Depending on the geologic structure, size of the reservoir and whether it is oil or gas, spacing could be as small as 10 acres and as large as 640 acres. Wellhead – Flow control equipment located at the top of the casing string at the surface of the wellbore. Wildcat – An exploratory well drilled in an unknown or unproven area. Workover – Essentially, refurbishment of a well to improve its flow rate. Workover includes any of several operations on a well to restore or increase production when a reservoir stops producing at the rate it should. Many workover jobs involve treating the reservoir rock, rather than the equipment in the well. Workover jobs typically take a few days to several weeks to complete. Working interest (WI) – The interest in the oil and gas in place which is burdened with the cost of development and operation of the property. The mineral interest minus the royalty interest equals the working interest. Also called the operating interest.
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6. Additional Resources
Additional Resources Macro Information: http://www.naturalgas.org/index.asp http://www.eia.gov/natural_gas/data_publications/natural_gas_monthly/ngm.html http://www.woodmacresearch.com/cgi-bin/wmprod/portal/corp/corpPortal.jsp http://www.ihs.com/ http://www.oilandgasinvestor.com/ http://www.UGcenter.com http://www.info.drillinginfo.com Public Filings: http://www.sec.gov/edgar/searchedgar/companysearch.html http://www.sedar.com/search/search_form_pc_en.htm Rig Counts: http://investor.shareholder.com/bhi/rig_counts/rc_index.cfm http://www.smithprodserv.com/%24ca88deed-1360-463d-a271-5b959eb7fb87 Glossaries: http://www.spe.org/industry/docs/GlossaryPetroleumReserves-ResourcesDefinitions_2005.pdf http://www.spectraenergy.com/Natural-Gas-101/Glossary-of-Energy-Terms/ http://media.corporate-ir.net/media_files/irol/70/70888/pdf/Glossary_of_Drillings_Terms_041805.pdf http://www.glossary.oilfield.slb.com/default.cfm http://www.eia.gov/emeu/iea/glossary.html 47