The document discusses gas economics and valuation. It introduces key concepts like determining gas compositions using chromatography, and calculating the gross heating value (GHV) of natural gas using composition percentages and heating values of individual components. Costs involved include capital expenditures (CAPEX), operating expenditures (OPEX), and abandonment costs. Revenue is calculated based on gas sales prices and annual production volumes. An example calculation is provided to estimate project cash flows, net present value, discount rate of return, and breakeven price based on given gas reservoir and economic parameters.

1. Gas economics
Dr. Khaled Saeed Ba-Jaalah
Petroleum Economics- PET 511
Level-5 Semester-9
‫حضرمـــوت‬ ‫جــــامعة‬
HADRAMOUT UNIVERSITY
‫البترولية‬ ‫الهندسة‬ ‫قسم‬
DEPARTMENT OF PETROLEUM
ENGINEERING
‫البترول‬ ‫و‬ ‫الهندسـة‬ ‫كليـة‬
FACULTY OF ENGINEERING
& PETROLEUM
29/11/2022

2. Introduction
Economics yardsticks is applied the same as
before; i.e. in crude oil economics.
Determine gas compositions thru gas
chromatography.
The higher the heavier components the higher the
value of natural gas.
Table (3-1) shows the typical composition for both
associated gas and non- associated gas.
2

3. 3
Associated Gas
Non-Associated gas
Component
0.0168
0.0131
N2
0.0562
0.0411
CO2
0.0328
0.042
H2S
0.3073
0.59
C1
0.2254
0.11
C2
0.2147
0.088
C3
0.0537
0.052
i-C4

4. 0.0536
0.05
n-C4
0.0159
0.007
i-C5
0.0159
0
n-C5
0.0066
0.005
C6
0.0011
0.0018
C7+
4

5. Introduction :(cont.)
5
Sale price is determined using Gross
Heating Values utilizing the British Thermal
Units (BTU).
Table (3-2) gives the BTU values for the
different composition of natural gas.

6. 6
Cross Heating
Values
(BTU/SCF)
Component
Cross Heating
Values
(BTU/SCF)
Component
3253
n-C4
0
N2
4010
i-C5
0
CO2
4000
n-C5
637
H2S
4756
C6
1010
C1
5503
C7
1769
C2
6250
C8
2517
C3
6997
C9
3262
i-C4

7. Introduction :(cont.)
7
Example (3-1):
Determine the Gross Heating Values (BTU/SCF)
for the gas composition given in Table (3-1)?
Solution:
1-For associated gas:

8. 8
GHV
(BTU/SCF)
GHV (BTU/SCF)
from Table (3-2)
Composition
Component
0
0
0.0168
N2
0
0
0.0562
CO2
20.8936
637
0.0328
H2S
310.373
1010
0.3073
C1
398.7326
1769
0.2254
C2
540.3999
2517
0.2147
C3
175.1694
3262
0.0537
i-C4
174.3608
3253
0.0536
n-C

9. 63.759
4010
0.0159
i-C5
63.6
4000
0.0159
n-C5
31.3896
4756
0.0066
C6
6.0533
5503
0.0011
C7+
1784.7312
1.000
Total
9

10. Introduction :(cont.)
10
2- For non-associated gas:
GHV
(BTU/SCF)
GHV (BTU/SCF)
from Table (3-2)
Composition
Component
0
0
0.0131
N2
0
0
0.0411
CO2
26.754
637
0.042
H2S
595.9
1010
0.59
C1
194.59
1769
0.11
C2
221.496
2517
0.088
C3

11. 169.624
3262
0.052
i-C4
162.65
3253
0.05
n-C4
28.07
4010
0.007
i-C5
0
4000
0
n-C5
23.78
4756
0.005
C6
9.9054
5503
0.0018
C7+
1432.7694
1.000
Total
11

12. Costs and Revenues
12
1. Costs:
In order to produce the petroleum there are
two main types of costs:
1. Fiscal costs which include bonuses, royalties
and taxes.
2. Field costs which can be classified into four
elements:

13. Costs and Revenues
A. Exploration costs
B. Development costs
C. Operating costs
D. Abandonment costs
13

14. Costs and Revenues
Exploration and development costs together are
termed CAPEX, while the operating cost is called
OPEX.
The abandonment cost is considered to be a
special category of cost because it is associated
with environmental safety and does not produce
any future profit for the company.
14

15. Costs and Revenues
15
It is also a very large cost component, and could be
equal to or more than the development cost.
The allocation of field cost (CAPEX, OPEX) into
elements differs from company to company, due to
the variable nature of petroleum projects (e.g.
different reservoir types) and the fiscal regime
applied in the project (e.g. some host governments
determine the cost which will be capitalized and the
cost which will be depleted).

16. Capital Cost (CAPEX)
16
Usually, it is paid only once at the beginning of the
project, although sometimes CAPEX occurs during
the economic life of the project; for example, if the
project applies new techniques and facilities in order
to increase petroleum production.
It is divided into 3years:
1. 20% at the first year
2. 50% at the second year
3. 30% at the third year

17. Capital Cost (CAPEX)
According to the purpose of the cost, the CAPEX
can be broken down into two main categories:
1-Exploration cost:
The exploration cost contains the costs of
geological and geophysical studies which are made
by the company itself or purchased from other
parties like service companies.
17

18. Capital Cost (CAPEX)
18
 In addition, exploration wells are drilled and their
cost is considered as exploration costs.
 If the exploration effort is unsuccessful, then the
cost is called sunk cost.
 Usually the sunk cost does not appear directly in
the project future cash flow evaluation, but it
affects the actual financial situation of the
project.

19. Capital Cost (CAPEX)
19
2-Development cost:
The development cost consists of three main cost
elements:
1. Development well drilling cost
2. Production installation cost
3. Cost of facilities required for petroleum
transportation.

20. Capital Cost (CAPEX)
The development methods and techniques
differ from project to project depending on
various factors, such as onshore/offshore,
technologies available, rock type, the size of
the oil or gas fields, etc.
20

21. Operating Cost (OPEX)
21
The operating cost (OPEX) represents the cost of
operating and maintaining the petroleum project.
It is occurred periodically.
Operating cost may be classified on to:
1. Feedstock
2. Utilities
3. Maintenance of facilities
4. Overheads

22. Operating Cost (OPEX)
5. Production costs which includes:
 Treatment Costs
 Workover
 Secondary recovery costs
 Water disposal costs
6. Evacuation costs
7. Insurance costs
22

23. Abandonment cost
23
Abandonment cost is the cost paid for cleaning
up the wells and facilities, and the restoration of
the production site after production ends.
This cost is incurred at the end of project life; in
some regimes the abandonment payment is
allowed to be funded in advance through
deductions from annual profits (abandonment
provision or contribution).

24. Abandonment cost
The abandonment cost covers the cost of
wellhead removal in addition to removal of
the production and petroleum transport
equipment, plugging of the well and
treatment and restoration of the production
area.
24

25. Revenue
25
Revenue arises from petroleum
production sales (oil, gas or condensate)
in addition to other activities such as
money received from asset sales or
interest on the provisions(abandonment,
depreciation and others).

26. Revenue
In order to calculate the revenue from
petroleum sales, the prices should be
predicted.
For each project the price forecasts should be
chosen depending on the expertise of the
economist.
26

27. Example
27
CAPEX 5,000,000,000 $
OPEX 3.0% ofCAPEX
Reserves 10,000,000 MMSCF
Production 2000 MMSCFD
Sales Price 2.00 $/mmbtu
Hurdle Rate 15.0%
Decline Start 60% Oforiginalreserves
Decline % 5%
Composition Mole%
N2 0.20
H2S 0.10
CO2 0.05
C1 0.50
C2 0.10
C3 0.05
C4 0.00

28. Solution:-
28
R/P 13.70 Years
Platue 8.22 Years
Composition Mole% HeatingValue,btu/SCF GHV
N2 0.20 0 0
H2S 0.10 637 64
CO2 0.05 0 0
C1 0.50 1010 505
C2 0.10 1769 177
C3 0.05 2517 126
C4 0.00 3262 0
Cum= 871.45 BTU/SCF

29. Solution:(cont.)
29
2.
Year ProductionRate,MMSFD Volume,MMSCF/yr Cum.MMSCF CAPEX,$ OPEX, $ MM btu/yr GrossRevnue($)
1 $1,000,000,000 $0
2 $2,500,000,000 $0
3 $1,500,000,000 $0
4 2000 730,000 730,000 $150,000,000 636,158,500 $1,272,317,000
5 2000 730,000 1,460,000 $150,000,000 636,158,500 $1,272,317,000
6 2000 730,000 2,190,000 $150,000,000 636,158,500 $1,272,317,000
7 2000 730,000 2,920,000 $150,000,000 636,158,500 $1,272,317,000
8 2000 730,000 3,650,000 $150,000,000 636,158,500 $1,272,317,000
9 2000 730,000 4,380,000 $150,000,000 636,158,500 $1,272,317,000
10 2000 730,000 5,110,000 $150,000,000 636,158,500 $1,272,317,000
11 2000 730,000 5,840,000 $150,000,000 636,158,500 $1,272,317,000
12 1900 693,500 6,533,500 $150,000,000 604,350,575 $1,208,701,150
13 1805 658,825 7,192,325 $150,000,000 574,133,046 $1,148,266,093
14 1715 625,884 7,818,209 $150,000,000 545,426,394 $1,090,852,788
15 1629 594,590 8,412,798 $150,000,000 518,155,074 $1,036,310,148
16 1548 564,860 8,977,658 $150,000,000 492,247,321 $984,494,641
17 1470 536,617 9,514,275 $150,000,000 467,634,955 $935,269,909
18 1331 485,725 10,000,000 $150,000,000 423,284,916 $846,569,832
Total 10,000,000 $5,000,000,000 $2,250,000,000 8,714,500,281 $17,429,000,561

30. Solution:(cont.)
30
Net, $/Yr Undiscounted Cum, $
-$1,000,000,000 -$1,000,000,000
-$2,500,000,000 -$3,500,000,000
-$1,500,000,000 -$5,000,000,000
$1,122,317,000 -$3,877,683,000
$1,122,317,000 -$2,755,366,000
$1,122,317,000 -$1,633,049,000
$1,122,317,000 -$510,732,000
$1,122,317,000 $611,585,000
$1,122,317,000 $1,733,902,000
$1,122,317,000 $2,856,219,000
$1,122,317,000 $3,978,536,000
$1,058,701,150 $5,037,237,150
$998,266,093 $6,035,503,243
$940,852,788 $6,976,356,030
$886,310,148 $7,862,666,179
$834,494,641 $8,697,160,820
$785,269,909 $9,482,430,729
$696,569,832 $10,179,000,561
$10,179,000,561
Undiscounted
ROI 140.40%
LRMC 0.83 $/MM btu

31. Solution:(cont.)
31
CAPEX, $ OPEX, $ Discounted Net @ HR Discounted Cum @ HR
$869,565,217 -$869,565,217 -$869,565,217
$1,890,359,168 -$1,890,359,168 -$2,759,924,386
$986,274,349 -$986,274,349 -$3,746,198,734
$85,762,987 $641,688,387 -$3,104,510,347
$74,576,510 $557,989,902 -$2,546,520,445
$64,849,139 $485,208,610 -$2,061,311,834
$56,390,556 $421,920,531 -$1,639,391,304
$49,035,266 $366,887,418 -$1,272,503,886
$42,639,362 $319,032,537 -$953,471,348
$37,077,706 $277,419,598 -$676,051,750
$32,241,483 $241,234,433 -$434,817,317
$28,036,073 $197,878,815 -$236,938,502
$24,379,194 $162,246,148 -$74,692,354
$21,199,299 $132,969,462 $58,277,108
$18,434,173 $108,922,629 $167,199,737
$16,029,715 $89,178,078 $256,377,815
$13,938,883 $72,971,903 $329,349,717
$12,120,768 $56,286,408 $385,636,126
$3,746,198,734 $576,711,114 $385,636,126 $385,636,126
Dicounted
NPV $385,636,126
DROI 8.92%
IRR 16.85%
LRMC 1.84 $/MM btu

32. Solution:(cont.)
32
Production Rate vs. Time
1330
1430
1530
1630
1730
1830
1930
2030
0 2 4 6 8 10 12 14 16
Time, Years
Gas
Daily
Production,
MMSCFD

33. Solution:(cont.)
33
Renue Streams
-$5
-$4
-$3
-$2
-$1
$0
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
$11
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18
Billions
Time, Years
Cum.
Revenue,
$
Undiscounted Cum, $
Discounted Cum @ HR

34. Solution:(cont.)
34
+ 50% - 50%
OPEX $1,516,394,804 $2,373,578,821
CAPEX -$534,694,602 $4,424,668,227
HR $385,636,126 $4,785,163,869
Gas Price $5,397,161,633 -$1,507,188,009
NPV

35. Solution:(cont.)
35
-2.0 -1.0 0.0 1.0 2.0 3.0 4.0 5.0 6.0
OPEX
CAPEX
HR
Gas
Price
NPV, Billions $
- 50%
+ 50%
- 50% + 50%
- 50%
- 50%
+ 50%
+ 50%
Project Current NPV

36. 36