Renewable Energy Finance : Mesteno Wind Decision Business Case: Wind Investment Decision

The Task is regarding Renewable Energy Finance. Answer the Question in the document. In The PPT Untill Slide 37 you can find the Theory to solve the question from Slide 38 you can go through the additional information to solve assignment problem in detail with respect to the Case provided in the document. Both documents contain the problem statement so need to go through both documents

MBA 833 Mod IV 2024
Mid Term Exam
Mesteno Wind Decision Business Case
Project Description:
200 MW Wind Project
Location – South Texas
ERCOT Market, South Texas Hub
100% PTC Qualified for 2019 COD
Current Development investment – $500,000
Transmission Study required:
$1 million due immediately
Additional $1 million due in 6 months
Total project cost – $200 million ($1000 per kw)
Project/Asset characteristics:
Useful life 30 years
Vestas Turbines V136-3.6 (3.6 MW, 136 meter rotor)
105 meter tower height
55 turbines
345kV transmission interconnection
10,000 square miles of leased land
Expected (P50) capacity factor of 40%
Key Milestone and Financial Commitments:
April –
Sign Generation Interconnection Agreement (GIA) and commit $1million to
support transmission interconnection work
July Make decision on revenue stream: contract PPA, Hedge or Merchant
August Final approval to proceed, with project financing in-place
September – Pay additional $1 million for transmission interconnection work
October Make Long Lead Equipment (LLE) deposits/commitments
December – Construction FNTP
Jan
Transmission interconnection construction works begins
October Transmission back feed
December – Commercial Operation Date (COD)
Investment Decisions:
NO-GO –
Write-off $500,000, move on to next project (assuming you can)
GO –
Invest initial $1million in GIA and
1) Sell project with IA to third party to earn Dev Fee, or
2) Determine revenue stream approach to support financing
and returns and proceed to construct
Revenue Stream Decision:
Utility (or coop, muni) PPA ,or
Corporate Buyer PPA ,or
LT Financial Hedge with financial institution, or
Merchant – spot market sales
And PTCs – Production Tax Credits
And RECs – Renewable Energy Credits
Assignment:
1) Discuss and determine GO/NO-GO decision risks, considerations and tradeoffs
a. NO-GO, and why?
b. GO, but sell to third party
2) Assuming a GO decision with long-term ownership and operation, then
a. Compare risk/returns of various revenue streams
b. Make revenue stream decision
c. Support your decision
d. How do you de-risk the project to get comfortable with an investment?
Work individually or in groups. Write-up and turn in your 2 page paper
individually.
Prepare a 2 page paper – What’s your decision and why?
Additional Information and Project Economics: (see power point slides)
Wind Project Off-take options
Hedge Details
Risks and Mitigations
Basis
Load Shape
Other Factors
Volume
RECs
PTC
Post contract period revenues – tail period
Hedge sensitivities
PPA differences and Challenges
Wind Investment Discussion
Markets & Off-Take Agreements
Capacity Factor
Resource Factors – P99 and P50
Project Revenue – PPA, VPPA, Financial Hedge, Spot Market, PTC,
Residual
• Risks and Mitigation
• Basis
• Shape
• Hedge Settlement
• Tail
• Fixed for Floating Contract for differences
• Mesquite Creek Wind (MCW)/Mars Candy
•
•
•
•
1
Markets and Off-Take Agreements
• Regulated Markets
• IOU
• Green Tariffs
• Mandates
• PURPA
• Resource Plans
• Organized Markets
• ERCOT – Texas
• CAISO – California
• PJM – Mid-Atlantic
• MISO – Midwest
• ISO-NE – New England
• Energy and Capacity
Markets
•
Bilateral Markets
•
COOP
•
Muni
•
Corporate Buyers
•
Direct Sales to EndUse Customers
2
Corporate Purchasers Buying Wind Energy
3
Wind Project Revenue Streams and Risks
• Physical delivery – direct customers interconnection
• Virtual delivery – high price volatility
4
How does a generator finance a project with
high price volatility?
The Business Case for Renewable Energy: A Guide for
Colleges and Universities
5
PPA Differences
Traditional Utility PPA
Corporate Virtual PPA
Term
15-30 years
12-15 years
Target Size
MW
MWh
Settlement
Busbar / Node
Hub
Buyer Price
Protection
Buyer curtailment buckets
Zero price floor
Environmental
Attributes
Less key (unless RPS)
Key driver, also “Additionality”
Project Perception
Sensitive to community issues
Market Participant
Utility
Developer / Owner
Credit
Generally creditworthy
Sometimes not investment grade,
requires LoC
Price
Lower
Higher (covers higher seller risk)
Newer Asks
Integration charges
Exotic settlement structures
Aggregate small buyers
6
Market
Utility PPA
• Renewable Energy
Credits
$
Ind. Power
Prod.
Power Purchase
Agreement
$
Tax Equity
Partner
Renewable
Energy
Credits
Power Plant
Utility
Production
Tax Credits
$
Consumer
$
Electricity
Price
7
Virtual PPA Mechanics
Renewable Energy Project
Corporate Customer
Fixed price
($/MWh)
2 “Contract For Differences”
Variable price
at Hub ($/MWh)
3
Electricity
1
Environmental
Attributes (RECs)
Variable price
at POI ($/MWh)
1 Project sells electricity at POI (Nodal price*) into
the wholesale market
2 Project settles “Contract For Differences” with
buyer. Pays Hub price* to buyer, receives fixed PPA
price.
3
Project bundles environmental attributes with PPA
allowing buyer to retire the RECs
8
Electricity Market
* Hub Price – Nodal Price = Basis Exposure
Resources Factors
• P50 – equal chance actual production will be above and below this
resource factor (project capacity factor)
• P99 – significant chance that actual production will be above this
resource factor
• Generally P99 production is about 75% to 80% of total production and
P50 is about 20% to 25% of total production
9
Resources Factors (P99, P95, P50)
10
Capacity Factor
• Expected (P50) Capacity Factor = 40%
• 8760 hours per year x 40% = 3504 hours of production per
year
• MCW Project is 211 MW: 3504hrs x 211MW = 739,344
MWhrs of electricity generation per year
• Project revenue is based upon expected P50 capacity
factor assumption
• P99 MWhrs = 75% of hours = 554,508 hours
• Excess MWhrs = 25% of hours = 184,836 hours
11
Project Revenue
• Modeled at P50 expected Capacity Factor
• Bi-Lateral Purchase Power Agreement (PPA)
• Virtual Purchase Power Agreement (VPPA)
• Financial Hedge Market
• Spot Market
• Tax Credits
• Residual Value
12
Risks and Contracting
• Basis Risk and Mitigation
• Shape Risk and Mitigation
• Hedge Risk
• Tail Risk
13
Basis Risk: that the hub LMP will deviate from
project node LMP
• Project Node LMP vs. ERCOT Hub LMP Both for MCW
project:
• Project Node LMP vs ERCOT North Hub LMP
• Project Node LMP vs ERCOT West Hub LMP
• LMP = locational marginal price (market price)
• Project Node LMPs and Hub LMPs are floating market
prices
• Basis can be positive or negative
14
Basis Risk: Risk that Hub LMP will deviate from
project node LMP
“Node”
Project LMP $
Basis = Project Node LMP
vs Hub LMP
Actual Mwhr
Production
Transmission
Interconnection
• LMP = locational marginal pricing (market price)
• Node and Hub LMPs are floating market prices
Hub LMP $
“Hub”
15
Basis Risk
B
C
D
E
F
=B-A
MW
G
H
I
J
K
L
M
=F-E
=BxF
=AxD
=AxE
=I-J
= MIN(C,
=D-E
$ /MWh
Long
/
(Shor
Fixed
Floatin
g (Hub
LMP)
Project
Node
LMP
Basis
Gen
Revenu e
from
0)
(-1)
Shape Risk
Hedge Settlement
Fixed
Payme nt
Floatin
g Payme
Hour
Hedge
Actual
0
75
71
(4)
$
23.00
$
19.00
$
18.00
($1.00) $1,278
$
1,725
$
1
72
79
7
$
23.00
$
20.00
$
19.00
($1.00) $1,501
$
1,656
$
2
73
69
(4)
$
23.00
$
18.00
$
18.00
$0.00 $1,242
$
1,679
3
65
62
(3)
$
23.00
$
22.00
$
23.00
$1.00 $1,426
$
4
66
68
2
$
23.00
$
21.00
$
21.00
$0.00 $1,428
5
62
94
32
$
23.00
$
19.00
$
20.00
6
68
75
7
$
23.00
$
17.00
$
7
57
72
15
$
23.00
$
19.00
8
40
51
11
$
23.00
$
21.00
9
45
49
4
$
23.00
$
10
53
38
(15)
$
23.00
11
54
33
(21)
$
12
54
24
(30)
$
13
47
41
(6)
14
48
53
15
47
16
45
17
N
Fixed
Float
Net
Short MW
1,425
$300
(4)
$4.0
1,440
$216
0
$3.0
$
1,314
$365
(4)
1,495
$
1,430
$65
$
1,518
$
1,386
$1.00 $1,880
$
1,426
$
16.00
($1.00) $1,200
$
1,564
$
18.00
($1.00) $1,296
$
$
21.00
$0.00 $1,071
$
23.00
$
23.00
$0.00 $1,127
$
22.00
$
23.00
23.00
$
27.00
$
23.00
$
30.00
$
$
23.00
$
29.00
5
$
23.00
$
58
11
$
23.00
49
4
$
23.00
50
61
11
$
18
56
50
(6)
19
73
61
20
78
21
83
22
=L xMx
Net
Shape
Impact
O
=A
P
Q
=G
=OxP
Basis Risk
Net
Basis
Impact
Basis
$16
Hedge
MW
75
$0
72
($1.00) ($72)
$5.0
$20
73
$0.00 $0
(3)
$1.0
$3
65
$1.00 $65
$132
0
$2.0
$0
66
$0.00 $0
1,178
$248
0
$4.0
$0
62
$1.00 $62
$
1,156
$408
0
$6.0
$0
68
($1.00) ($68)
1,311
$
1,083
$228
0
$4.0
$0
57
($1.00) ($57)
920
$
840
$80
0
$2.0
$0
40
$0.00 $0
$
1,035
$
1,035 $0
0
$0.0
$0
45
$0.00 $0
$1.00 $874
$
1,219
$
1,166
$53
(15)
$1.0
$15
53
$1.00 $53
28.00
$1.00 $924
$
1,242
$
1,458
($216)
(21)
($4.00)
($84)
54
$1.00 $54
31.00
$1.00 $744
$
1,242
$
1,620
($378)
(30)
($7.00)
($210)
54
$1.00 $54
$
30.00
$1.00 $1,230
$
1,081
$
1,363
($282)
(6)
($6.00)
($36)
47
$1.00 $47
33.00
$
31.00
($2.00) $1,643
$
1,104
$
1,584 ($480)
0
($10.00)
$0
48
($2.00) ($96)
$
36.00
$
35.00
($1.00) $2,030
$
1,081
$
1,692
($611)
0
($13.00)
$0
47
($1.00) ($47)
$
40.00
$
40.00
$0.00 $1,960
$
1,035
$
1,800
($765)
0
($17.00)
$0
45
$0.00 $0
23.00
$
33.00
$
34.00
$1.00 $2,074
$
1,150
$
1,650
($500)
0
($10.00)
$0
50
$1.00 $50
$
23.00
$
31.00
$
31.00
$0.00 $1,550
$
1,288
$
1,736
($448)
(6)
($8.00)
($48)
56
$0.00 $0
(12)
$
23.00
$
29.00
$
27.00
($2.00) $1,647
$
1,679
$
2,117
($438)
(12)
($6.00)
($72)
73
($2.00) ($146)
68
(10)
$
23.00
$
23.00
$
20.00
($3.00) $1,360
$
1,794
$
1,794 $0
$0
78
($3.00) ($234)
78
(5)
$
23.00
$
24.00
$
23.00
($1.00) $1,794
$
1,909
$
1,992
($83)
(5)
($5)
83
($1.00) ($83)
84
91
7
$
23.00
$
19.00
$
20.00
$1.00 $1,820
$
1,932
$
1,596
$336
0
$4.0
$0
84
$1.00 $84
23
81
95
14
$
23.00
$
17.00
$
17.00
$0.00 $1,615
$
1,863
$
1,377
$486
0
$6.0
$0
81
$0.00 $0
TOTAL
1,476
1,490
14
$
33,948
$
35,232
Net Generator Revenue after Hedge Settlement
$ 34,714
(10)
$0.0
($1.00)
0
($401)
($1.00) ($75)
($409)
$ 33,430
16
Basis Risk and Mitigation
• Basis Risk: risk that hub LMP will deviate from the project node LMP
• Mitigations
• Select a hub geographically correlated to project location (project is in west
Texas = ERCOT West Hub)
• Robust point of interconnection on 345kV system less likely to be impacted by
congestion than 115/69kV systems
• On-peak shape of project wind resource better correlated to peak demand
• Perform independent LMP and congestion study to forecast futurebasis based on
generation additions/retirements and transmission build-out
•
Include stress cases (increased wind additions, low gas prices, etc.)
• Review historical basis
•
Informative, but not necessarilyrepresentativeof thefuture
•
Project Node vs Hub LMP basis differences – positive and/or negative
17
Shape Risk: that production is less than the
hedged or contracted volume in any hour
• Fixed shape curve per hedge agreement vs actual project production• Hour by day for each day of year and each year of hedge
agreement
• Fixed shape curve based on P99 production
18
Fixed Hedge Shape Example
Hour
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Month
Jan
75
72
73
65
66
62
68
57
40
45
53
54
54
47
48
47
45
50
56
73
78
83
84
81
Feb
88
99
98
91
73
69
73
52
38
43
46
50
51
51
48
47
54
70
80
89
104
99
93
87
Mar
100
93
86
85
77
80
75
64
67
73
74
65
61
55
59
61
65
79
92
95
105
106
101
99
Apr
109
94
94
95
94
86
90
72
72
71
65
56
48
48
51
59
76
92
105
116
122
117
112
112
May
96
91
89
90
85
88
86
75
76
69
66
62
64
68
74
78
84
93
104
101
104
107
102
97
Jun
98
83
81
73
77
80
72
69
74
71
70
65
68
77
76
86
90
107
113
106
112
108
106
106
Jul
98
87
82
82
79
77
76
83
91
88
86
83
78
76
81
89
104
116
127
124
120
112
111
107
Sample 12×24 fixed hourly shape (truncated)
19
Shape Risk: that production is less than the
hedged/contracted volume in any hour
B
C
=B-A
MW
Hour
Long/
(Short)
Hedge
Actual
0
75
71
1
72
79
7
2
73
69
(4)
3
65
62
(3)
4
66
68
2
5
62
94
32
6
68
75
7
7
57
72
15
11
(4)
8
40
51
9
45
49
4
10
53
38
(15)
11
54
33
(21)
12
54
24
(30)
13
47
41
(6)
14
48
53
5
15
47
58
11
16
45
49
4
17
50
61
11
18
56
50
(6)
19
73
61
(12)
20
78
68
(10)
21
83
78
(5)
22
84
91
7
23
81
95
14
TOTAL
1,476
1,490
14
Sample 24 hours (in each day)
Net Generator Revenue after Hedge Settlement
20
Shape Risk
B
C
D
E
F
=B-A
MW
G
H
I
J
K
L
M
=F-E
=BxF
=AxD
=AxE
=I-J
= MIN(C,
=D-E
$ /MWh
Long
/
(Shor
Fixed
Floatin
g (Hub
LMP)
Project
Node
LMP
Basis
Gen
Revenu e
from
0)
(-1)
Shape Risk
Hedge Settlement
Fixed
Payme nt
Floatin
g Payme
Hour
Hedge
Actual
0
75
71
(4)
$
23.00
$
19.00
$
18.00
($1.00) $1,278
$
1,725
$
1
72
79
7
$
23.00
$
20.00
$
19.00
($1.00) $1,501
$
1,656
$
2
73
69
(4)
$
23.00
$
18.00
$
18.00
$0.00 $1,242
$
1,679
3
65
62
(3)
$
23.00
$
22.00
$
23.00
$1.00 $1,426
$
4
66
68
2
$
23.00
$
21.00
$
21.00
$0.00 $1,428
5
62
94
32
$
23.00
$
19.00
$
20.00
6
68
75
7
$
23.00
$
17.00
$
7
57
72
15
$
23.00
$
19.00
8
40
51
11
$
23.00
$
21.00
9
45
49
4
$
23.00
$
10
53
38
(15)
$
23.00
11
54
33
(21)
$
12
54
24
(30)
$
13
47
41
(6)
14
48
53
15
47
16
45
17
N
Fixed
Float
Net
Short MW
1,425
$300
(4)
$4.0
1,440
$216
0
$3.0
$
1,314
$365
(4)
1,495
$
1,430
$65
$
1,518
$
1,386
$1.00 $1,880
$
1,426
$
16.00
($1.00) $1,200
$
1,564
$
18.00
($1.00) $1,296
$
$
21.00
$0.00 $1,071
$
23.00
$
23.00
$0.00 $1,127
$
22.00
$
23.00
23.00
$
27.00
$
23.00
$
30.00
$
$
23.00
$
29.00
5
$
23.00
$
58
11
$
23.00
49
4
$
23.00
50
61
11
$
18
56
50
(6)
19
73
61
20
78
21
83
22
=L xMx
Net
Shape
Impact
O
=A
P
Q
=G
=OxP
Basis Risk
Net
Basis
Impact
Basis
$16
Hedge
MW
75
$0
72
($1.00) ($72)
$5.0
$20
73
$0.00 $0
(3)
$1.0
$3
65
$1.00 $65
$132
0
$2.0
$0
66
$0.00 $0
1,178
$248
0
$4.0
$0
62
$1.00 $62
$
1,156
$408
0
$6.0
$0
68
($1.00) ($68)
1,311
$
1,083
$228
0
$4.0
$0
57
($1.00) ($57)
920
$
840
$80
0
$2.0
$0
40
$0.00 $0
$
1,035
$
1,035 $0
0
$0.0
$0
45
$0.00 $0
$1.00 $874
$
1,219
$
1,166
$53
(15)
$1.0
$15
53
$1.00 $53
28.00
$1.00 $924
$
1,242
$
1,458
($216)
(21)
($4.00)
($84)
54
$1.00 $54
31.00
$1.00 $744
$
1,242
$
1,620
($378)
(30)
($7.00)
($210)
54
$1.00 $54
$
30.00
$1.00 $1,230
$
1,081
$
1,363
($282)
(6)
($6.00)
($36)
47
$1.00 $47
33.00
$
31.00
($2.00) $1,643
$
1,104
$
1,584 ($480)
0
($10.00)
$0
48
($2.00) ($96)
$
36.00
$
35.00
($1.00) $2,030
$
1,081
$
1,692
($611)
0
($13.00)
$0
47
($1.00) ($47)
$
40.00
$
40.00
$0.00 $1,960
$
1,035
$
1,800
($765)
0
($17.00)
$0
45
$0.00 $0
23.00
$
33.00
$
34.00
$1.00 $2,074
$
1,150
$
1,650
($500)
0
($10.00)
$0
50
$1.00 $50
$
23.00
$
31.00
$
31.00
$0.00 $1,550
$
1,288
$
1,736
($448)
(6)
($8.00)
($48)
56
$0.00 $0
(12)
$
23.00
$
29.00
$
27.00
($2.00) $1,647
$
1,679
$
2,117
($438)
(12)
($6.00)
($72)
73
($2.00) ($146)
68
(10)
$
23.00
$
23.00
$
20.00
($3.00) $1,360
$
1,794
$
1,794 $0
$0
78
($3.00) ($234)
78
(5)
$
23.00
$
24.00
$
23.00
($1.00) $1,794
$
1,909
$
1,992
($83)
(5)
($5)
83
($1.00) ($83)
84
91
7
$
23.00
$
19.00
$
20.00
$1.00 $1,820
$
1,932
$
1,596
$336
0
$4.0
$0
84
$1.00 $84
23
81
95
14
$
23.00
$
17.00
$
17.00
$0.00 $1,615
$
1,863
$
1,377
$486
0
$6.0
$0
81
$0.00 $0
TOTAL
1,476
1,490
14
$
33,948
$
35,232
Net Generator Revenue after Hedge Settlement
$ 34,714
(10)
$0.0
($1.00)
0
($401)
($1.00) ($75)
($409)
$ 33,430
21
Shape Risk and Mitigation
▪ Shape Risk: risk that production is less than the hedged volume in any hour
▪ If short to hedge volume, buy shortfall MWh at floating hub price
▪ If long to hedge volume, sell excess MWh at floating project node price
▪ Mitigations
▪ Hedge expected P99 volumes, not P50
▪ P99 ~80% of P50 for a long-term period
▪
P99 ~75% of P50 for a 1-year period (finest resolution studied)
▪ Meteorologist assigns uncertainties to each variable in the wind resource assessment and calculates
a probability distribution curve
▪ Over a year period and longer we expect production to reflect the shape, but know that
it will deviate in any hour
22
Hedge Settlement Risk: That the Hedge
volume @ Fixed Price minus Hedge
volume @ Floating Price (ERCOT North Hub
LMP) is negative
23
Sample 24 hour Hedge Settlement Calculation
B
C
D
E
F
=B-A
MW
G
H
I
=F-E
=BxF
=AxD
$ /MWh
Long
/
(Shor
Gen
Revenu e
from
Project
Node
LMP
Basis
23.00
$
19.00
$
18.00
($1.00) $1,278
$
1,725
$
23.00
$
20.00
$
19.00
($1.00) $1,501
$
1,656
$
$
23.00
$
18.00
$
18.00
$0.00 $1,242
$
1,679
(3)
$
23.00
$
22.00
$
23.00
$1.00 $1,426
$
68
2
$
23.00
$
21.00
$
21.00
$0.00 $1,428
62
94
32
$
23.00
$
19.00
$
20.00
6
68
75
7
$
23.00
$
17.00
$
7
57
72
15
$
23.00
$
19.00
8
40
51
11
$
23.00
$
21.00
9
45
49
4
$
23.00
$
10
53
38
(15)
$
23.00
11
54
33
(21)
$
12
54
24
(30)
13
47
41
14
48
15
16
Hedge
Actual
0
75
71
(4)
$
1
72
79
7
$
2
73
69
(4)
3
65
62
4
66
5
=AxE
=I- J
L
0)
M
= MIN(C,
Fixed
Payme nt
Floatin
g Payme
N
=D-E
=L xMx
(-1)
Shape Risk
Fixed
Float
Net
Short MW
1,425
$300
(4)
$4.0
1,440
$216
0
$3.0
$
1,314
$365
(4)
1,495
$
1,430
$65
$
1,518
$
1,386
$1.00 $1,880
$
1,426
$
16.00
($1.00) $1,200
$
1,564
$
18.00
($1.00) $1,296
$
$
21.00
$0.00 $1,071
$
23.00
$
23.00
$0.00 $1,127
$
22.00
$
23.00
23.00
$
27.00
$
$
23.00
$
30.00
(6)
$
23.00
$
53
5
$
23.00
47
58
11
$
45
49
4
$
17
50
61
11
18
56
50
19
73
20
21
Net
Shape
Impact
O
=A
P
Q
=G
=OxP
Basis Risk
Net
Basis
Impact
Basis
$16
Hedge
MW
75
$0
72
($1.00) ($72)
$5.0
$20
73
$0.00 $0
(3)
$1.0
$3
65
$1.00 $65
$132
0
$2.0
$0
66
$0.00 $0
1,178
$248
0
$4.0
$0
62
$1.00 $62
$
1,156
$408
0
$6.0
$0
68
($1.00) ($68)
1,311
$
1,083
$228
0
$4.0
$0
57
($1.00) ($57)
920
$
840
$80
0
$2.0
$0
40
$0.00 $0
$
1,035
$
1,035 $0
0
$0.0
$0
45
$0.00 $0
$1.00 $874
$
1,219
$
1,166
$53
(15)
$1.0
$15
53
$1.00 $53
28.00
$1.00 $924
$
1,242
$
1,458
($216)
(21)
($4.00)
($84)
54
$1.00 $54
$
31.00
$1.00 $744
$
1,242
$
1,620
($378)
(30)
($7.00)
($210)
54
$1.00 $54
29.00
$
30.00
$1.00 $1,230
$
1,081
$
1,363
($282)
(6)
($6.00)
($36)
47
$1.00 $47
$
33.00
$
31.00
($2.00) $1,643
$
1,104
$
1,584 ($480)
0
($10.00)
$0
48
($2.00) ($96)
23.00
$
36.00
$
35.00
($1.00) $2,030
$
1,081
$
1,692
($611)
0
($13.00)
$0
47
($1.00) ($47)
23.00
$
40.00
$
40.00
$0.00 $1,960
$
1,035
$
1,800
($765)
0
($17.00)
$0
45
$0.00 $0
$
23.00
$
33.00
$
34.00
$1.00 $2,074
$
1,150
$
1,650
($500)
0
($10.00)
$0
50
$1.00 $50
(6)
$
23.00
$
31.00
$
31.00
$0.00 $1,550
$
1,288
$
1,736
($448)
(6)
($8.00)
($48)
56
$0.00 $0
61
(12)
$
23.00
$
29.00
$
27.00
($2.00) $1,647
$
1,679
$
2,117
($438)
(12)
($6.00)
($72)
73
($2.00) ($146)
78
68
(10)
$
23.00
$
23.00
$
20.00
($3.00) $1,360
$
1,794
$
1,794 $0
$0
78
($3.00) ($234)
83
78
(5)
$
23.00
$
24.00
$
23.00
($1.00) $1,794
$
1,909
$
1,992
($83)
(5)
($5)
83
($1.00) ($83)
22
84
91
7
$
23.00
$
19.00
$
20.00
$1.00 $1,820
$
1,932
$
1,596
$336
0
$4.0
$0
84
$1.00 $84
23
81
95
14
$
23.00
$
17.00
$
17.00
$0.00 $1,615
$
1,863
$
1,377
$486
0
$6.0
$0
81
$0.00 $0
TOTAL
1,476
1,490
14
$
33,948
$
35,232
Net Generator Revenue after Hedge Settlement
Fixed
K
Hedge Settlement
Floatin
g (Hub
LMP)
Hour
J
$ 34,714
(1284)
$ 33,430
V
(1284)
(10)
$0.0
($1.00)
0
($401)
($1.00) ($75)
($409)
Generator receives $34,714 from ERCOT (outside hedge settlement), pays hedge counterparty $1,284 for net revenues of
$33,430
Tail Risk: That the revenue from the
“uncontracted” period will be below the forward
price curve
Tail Risk/ Merchant curve/price risk
• Revenue stream from end of contracted period period to end of
useful life of project?
• What about decommissioning risk/costs?
25
Forward Curve Risk
26
Contract for Differences Case Study
MARS Candy & Mesquite Creek Wind (MCW) Project
•
MCW is a 211MW project in west
Texas
MCW
SW1-5
OCO
NOT
West Texas project cluster
MCW turbine layout
27
MCW Offtake Agreements
• MCW has two offtake agreement for years 1-7
• BP Hedge for fixed hourly P99 energy quantities
• Mars PPA for all energy above P99 and all RECs
• Mars then resells the energy to Pacific Summit Energy (PSE) at market price but
retains the RECs
• For years 8-20, MCW settles all electricity and delivers all RECs to Mars
under a fixed/floating contract for differences (CFD)
• Extendable at Mars’ option for additional 5 years
• Net result: MCW has contracted revenue streams for 100% of
energy and RECs for 20 years
• But exposed to basis risk
28
MCW Offtake Agreements
Years 1-7
Years 8-20
Energy generated in
excess of P99 &
All RECs
All Energy & RECs
Fixed/Floating CFD*
Mars
Fixed price
Fixed
price*
P99
Energy
BP
Excess
Energy
Mars
Mkt
price
Pacific
Summit
Energy
* Agreements where MCW wears basis risk
29
Yrs 1-7 Hedge Agreement Risks – settlement,
shape and basis -P99 volume
30
Yrs 1-7 excess energy revenue and basis risk
31
Yrs 8-20 all energy revenue and basis risks
32
Summary MCW Revenue and Risks
• Yrs 1 – 7:
• P99 energy revenue @ Fixed Price of Hedge plus/minus:
• Basis risk – Project Node vs ERCOT North Hub LMP
• Shape risk – actual production vs hedged shape
• Hedge settlement risk – hedge volume delta between fixed price and floating
price
• Plus excess energy revenue @ Fixed Price of PPA plus/minus:
• Basis risk – Project Node vs ERCOT West Hub LMP
• Plus all REC revenue @ Fixed Price per PPA
33
Summary MCW Revenue and Risks
• Yrs 8 – 20:
• Total energy production revenue @ Fixed Price of PPA plus/minus:
• Basis risk – Project Node vs West Hub LMP
• Plus total REC revenue @ Fixed Price per PPA
34
Summary MCW Revenue and Risks
• Yrs > 20: (or > yr 25 if Mars executes its 5 yr option)
• Total energy production revenue @:
•
•
•
•
New Fixed Price of new PPA
New CFD – VPPA
New financial hedge
The then current spot market price
• Plus total REC revenue (if market exists)
• Plus/minus:
• All specific contract structure risks
35
MCW Offtake Agreements
Basis Risk
• MCW is exposed to basis risk during all years of the offtake
agreements
• BP hedge settles at ERCOT North Hub
• Mars PPA has no basis risk, but under a separate agreement MCW keeps PSE whole
for Project LMP to ERCOT West Hub basis for this volume
• Mars CFD settles at ERCOT West Hub
MCW wears basis risk from the Project LMP to:
Years 1-7
P99 Energy
ERCOT North Hub
Excess Energy
ERCOT West Hub
•
Years 8-20
ERCOT West Hub
Project LMPs > Hub prices benefit the project, Project LMPs < Hub prices hurt the project 36 MCW Offtake Agreements Mars Reimbursement Risk • Under a separate Loss Reimbursement Agreement (LRA), MCW indemnifies Mars from losses greater than $X million over the PPA and CFD term • Tracking account quantifies gain or loss to Mars by comparing fixed PPA/CFD price v. ERCOT West Hub price plus. 37 Assignment Mesteno Wind Investment Decision 38 Mesteno Wind Investment Decision MOD IV 2023 39 Mesteno Wind Project Description • Size – 200MW • Location – South Texas • Market – ERCOT, South Hub • PTC – 100% Qualified for 2019 COD • Total Project Cost - $200 Million • Off-take Options: • Utility PPA • Corporate PPA • Financial Hedge • Project Characteristics • Vestas V 136-3.6 Turbines • 105 Meter Tower Height • 63 Turbines • 345 KV Transmission Interconnection • 10,000 Square Miles • Expected (P50) capacity factor of 40% • Procurement 40 Mesteno Wind Project Offtake Options 2012 Wind MW Build by Offtake Type Utlilty PPA Corporate PPA Hedge/Merchant 2017 Wind MW Build by Offtake Type Utlilty PPA Corporate PPA Hedge/Merchant Unknown 8% 16% 2% 24% 43% 82% 25% 41 Mesteno Wind Project Offtake Options Utility PPA Corporate PPA Hedge Merchant 15-20 years 12-15 years 12-15 years NA Project busbar Hub Hub Hub Basis Risk No Yes Yes Yes Shape Risk No No Yes No Includes RECs Yes Yes No No Contracted Energy Volume 100% 100% 75-80% (P99) NA “Contracted” PTC Volume 100% 100% 100% NA Typical Return (IRR) 7.5 – 8.5% 8.5 – 9.5% 9.5% + ? Difficult to obtain – few muni/coop buyers in ERCOT market; competitive bidding Growing – limited buyers at 200MW scale; competitive bidding More available – 3-5 banks active in ERCOT hedge market Go For It $15/Mwhr $18/Mwhr $23/Mwhr Mkt 42 Term Settlement Location Availability Assumed Price Hedge Details • Fixed for floating swap based on ISDA with Power Annex Counterparty Product Term Shape Fixed Price Floating Price Settlement Interval Seller Credit Support Buyer Credit Support TBD, quotes from Morgan Stanley & Citi Firm Energy (LD) 12-15 years Fixed hourly volumes ~$23/MWh (indicative) ERCOT South Hub LMP Hourly, invoiced monthly Parent guaranty, LC, or project lien Parent guaranty or LC Hour Month Jan Feb Mar Apr May Jun Jul 0 75 88 100 109 96 98 98 1 72 99 93 94 91 83 87 2 73 98 86 94 89 81 82 3 65 91 85 95 90 73 82 4 66 73 77 94 85 77 79 5 62 69 80 86 88 80 77 6 68 73 75 90 86 72 76 7 57 52 64 72 75 69 83 8 40 38 67 72 76 74 91 9 45 43 73 71 69 71 88 10 53 46 74 65 66 70 86 11 54 50 65 56 62 65 83 12 54 51 61 48 64 68 78 13 47 51 55 48 68 77 76 14 48 48 59 51 74 76 81 15 47 47 61 59 78 86 89 16 45 54 65 76 84 90 104 17 50 70 79 92 93 107 116 18 56 80 92 105 104 113 127 19 73 89 95 116 101 106 124 20 78 104 105 122 104 112 120 21 83 99 106 117 107 108 112 22 84 93 101 112 102 106 111 23 81 87 99 112 97 106 107 Sample 12x24 fixed hourly shape (truncated) 43 Risks and Mitigation • Basis Risk: risk that hub LMP will deviate from the project node LMP • Mitigations • Select a hub geographically correlated to project location (Mesteno is in south Texas = ERCOT South Hub) • Robust point of interconnection on 345kV system less likely to be impacted by congestion than 115/69kV systems • All 31 nodes that make up ERCOT South Hub are on 345kV system • Include stress cases (increased wind additions, low gas prices, etc.) • Informative, but not necessarily representative of the future • On-peak shape of Mesteno wind resource better correlated to peak demand • Perform independent LMP & congestion study (in process) to forecast future basis based on generation additions/retirements and transmission build-out • Review historical basis Year Mesteno Node ERCOT South Hub Basis 2016 (May-Dec) $25.37 $24.38 $0.99 (+) 2017 $26.19 $25.61 $0.58 (+) 44 Risks and Mitigation • Shape Risk: risk that production is less than the hedged volume in any hour • If short to hedge volume, buy shortfall MWh at hub price • If long to hedge volume, sell excess MWh at project node price • Mitigations • Hedge expected P99 volumes, not P50 • P99 ~80% of P50 for a long-term period • P99 ~75% of P50 for a 1-year period (finest resolution studied) • Meteorologist assigns uncertainties to each variable in the wind resource assessment and calculates a probability distribution curve • Over a year period or longer we expect production to reflect the shape, but know that it will deviate in any hour 45 Other Factors • Volumes produced in excess of the hedged amount in any hour are sold at the project node price • ~25% of expected annual production • Pricing based on IHS Fall 2017 price forecast for ERCOT South Hub, adjusted for project shape • RECs are sold at market prices • Currently ~$0.50/MWh for 2018-2020 • Post-hedge revenues based on IHS forecast • Same methodology used for PPAs • Retain ability to re-hedge or sign PPA after initial hedge term • PTCs are not impacted by hedge and accrue for every MWh generated for first 10 years 46 Sources of Cash Flow • P99 volumes, a hedge provides strong support for contracted revenues when paired with large tax benefits • PTC present value based on current deferral, merchant component drops to 10% for a tax efficient project Hedge Components Bonus Depreciation 11% PTCs Hedge Merchant PPA Components Bonus Depreciation 12% PTCs PPA Merchant 0% 12% 50% 40% 37% 38% 47 Sample Hedge Settlement Calculation ▪ Sample 24 B hours C E MW A Hour F G H I J K L M N O P Q =F-E =BxF =AxD =AxE =I-J = MIN(C,0) =D-E = L x M x (-1) =A =G =OxP Gen Revenue from ERCOT Fixed Payment $ /MWh Long/ (Short) Shape Risk Floating Payment Net Short MW Fixed Net Shape Float Impact $/MWh $4.00 $16 Basis Risk Hedge MW Basis Net Basis Impact 0 75 71 (4) $ 23.00 $ 19.00 $ 18.00 ($1.00) $1,278 $ 1,725 $ 1,425 $300 (4) 75 ($1.00) ($75) 1 72 79 7 $ 23.00 $ 20.00 $ 19.00 ($1.00) $1,501 $ 1,656 $ 1,440 $216 0 $3.00 $0 72 ($1.00) ($72) 2 73 69 (4) $ 23.00 $ 18.00 $ 18.00 $0.00 $1,242 $ 1,679 $ 1,314 $365 (4) $5.00 $20 73 $0.00 $0 3 65 62 (3) $ 23.00 $ 22.00 $ 23.00 $1.00 $1,426 $ 1,495 $ 1,430 $65 (3) $1.00 $3 65 $1.00 $65 4 66 68 2 $ 23.00 $ 21.00 $ 21.00 $0.00 $1,428 $ 1,518 $ 1,386 $132 0 $2.00 $0 66 $0.00 $0 5 62 94 32 $ 23.00 $ 19.00 $ 20.00 $1.00 $1,880 $ 1,426 $ 1,178 $248 0 $4.00 $0 62 $1.00 $62 6 68 75 7 $ 23.00 $ 17.00 $ 16.00 ($1.00) $1,200 $ 1,564 $ 1,156 $408 0 $6.00 $0 68 ($1.00) ($68) 7 57 72 15 $ 23.00 $ 19.00 $ 18.00 ($1.00) $1,296 $ 1,311 $ 1,083 $228 0 $4.00 $0 57 ($1.00) ($57) 8 40 51 11 $ 23.00 $ 21.00 $ 21.00 $0.00 $1,071 $ 920 $ 840 $80 0 $2.00 $0 40 $0.00 $0 4 $ 23.00 $ 23.00 $ 23.00 $0.00 $1,127 $ 1,035 $ 1,035 $0 0 $0.00 $0 45 $0.00 $0 23.00 $ 22.00 $ 23.00 $1.00 $874 $ 1,219 $ 1,166 $53 (15) $1.00 $15 53 $1.00 $53 49 Basis Hedge Settlement Actual 45 Fixed Floating Project (Hub LMP) Node LMP Hedge 9 10 53 38 (15) $ 11 54 33 (21) $ 23.00 $ 27.00 $ 28.00 $1.00 $924 $ 1,242 $ 1,458 ($216) (21) ($4.00) ($84) 54 $1.00 $54 12 54 24 (30) $ 23.00 $ 30.00 $ 31.00 $1.00 $744 $ 1,242 $ 1,620 ($378) (30) ($7.00) ($210) 54 $1.00 $54 13 47 41 (6) $ 23.00 $ 29.00 $ 30.00 $1.00 $1,230 $ 1,081 $ 1,363 ($282) (6) ($6.00) ($36) 47 $1.00 $47 14 48 53 5 $ 23.00 $ 33.00 $ 31.00 ($2.00) $1,643 $ 1,104 $ 1,584 ($480) 0 ($10.00) $0 48 ($2.00) ($96) 15 47 58 11 $ 23.00 $ 36.00 $ 35.00 ($1.00) $2,030 $ 1,081 $ 1,692 ($611) 0 ($13.00) $0 47 ($1.00) ($47) 16 45 49 4 $ 23.00 $ 40.00 $ 40.00 $0.00 $1,960 $ 1,035 $ 1,800 ($765) 0 ($17.00) $0 45 $0.00 $0 17 50 61 11 $ 23.00 $ 33.00 $ 34.00 $1.00 $2,074 $ 1,150 $ 1,650 ($500) 0 ($10.00) $0 50 $1.00 $50 18 56 50 (6) $ 23.00 $ 31.00 $ 31.00 $0.00 $1,550 $ 1,288 $ 1,736 ($448) (6) ($8.00) ($48) 56 $0.00 $0 19 73 61 (12) $ 23.00 $ 29.00 $ 27.00 ($2.00) $1,647 $ 1,679 $ 2,117 ($438) (12) ($6.00) ($72) 73 ($2.00) ($146) 20 78 68 (10) $ 23.00 $ 23.00 $ 20.00 ($3.00) $1,360 $ 1,794 $ 1,794 $0 (10) 78 ($3.00) ($234) 21 83 78 (5) $ 23.00 $ 24.00 $ 23.00 ($1.00) $1,794 $ 1,909 $ 1,992 ($83) (5) 83 ($1.00) ($83) 22 84 91 7 $ 23.00 $ 19.00 $ 20.00 $1.00 $1,820 $ 1,932 $ 1,596 $336 0 $4.00 $0 84 $1.00 $84 23 81 95 14 $ 23.00 $ 17.00 $ 17.00 $0.00 $1,615 $ 1,863 $ 1,377 $486 0 $6.00 $0 81 $0.00 $0 TOTAL 1,476 1,490 14 $ 34,714 $ 33,948 $ Net Generator Revenue after Hedge Settlement ▪ D =B-A 35,232 ($1,284) $0.00 $0 ($1.00) ($5) ($401) $ 33,430 Generator receives $34,714 from ERCOT (outside hedge settlement), pays hedge counterparty 48 $1,284 for net revenues of $33,430 ($409) Hedge Merchant Price Sensitivities 49