October 24,
2008
Mr. H.
Christopher Owings
Assistant
Director
United
States Securities and Exchange Commission
100 F
Street, NE
Mail Stop
3561
Washington,
D.C. 20549-3561
RE: Calpine
Corporation
Form
10-K for Fiscal Year Ended December 31, 2007
Filed
February 29, 2008
File
No. 1-12079
Mr.
Owings:
This
letter is being furnished on behalf of Calpine Corporation in response to the
comments of the Staff of the Securities and Exchange Commission (the
“Commission” or the “Staff”) contained in a letter to Robert P. May, former
Chief Executive Officer of Calpine Corporation, dated September 25, 2008,
with respect to the above referenced filing and our Form 10-Q for the Quarterly
Period Ended June 30, 2008. As used in this letter, “we,” “us,”
“our,” the “Company” and “Calpine” refer to Calpine Corporation and its
subsidiaries unless the context requires otherwise.
For your
convenience, we have set forth the Staff’s comments in full followed by our
responses.
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 2 of
22
Form 10-K for Fiscal Year
Ended December 31, 2007
Environmental profile, page
11
|
|
1.
|
We
note your description of your geothermal power generation facilities
located in the Geysers region of northern California and that you own and
operate 17 of these facilities. Please insert a small-scale map
showing the location and access to each property, grouping them as may be
appropriate, as required by Instruction 3(b) to Item 102 of Regulation
S-K.
|
Response:
Instruction
3b to Item 102 of Regulation S-K requires a map with respect to “individual
properties … of major significance to an industry segment.” The Geysers are a
part of our West segment, which includes 47 facilities. None of our
Geysers facilities are considered to be individually significant, and, on a
collective basis, the 17 Geysers facilities are capable of producing
approximately 725MW, about average for a single combined cycle, natural
gas-fired power plant in our West segment. In addition, we have
presented information as to the location of each of our facilities in the table
“Power Plants in Operation and Under Construction/Development” beginning on page
14 of our Annual Report on Form 10-K for the year ended December 31, 2007
(the “2007 Form 10-K”).
In
order to more clearly indicate their locations, we propose to include in future
Form 10-K filings a map showing the location of our facilities. All
of our Geysers facilities are located in a small section of the Geysers
region and our map will therefore show our 17 geothermal plants at the
Geysers region as a single location. We do not believe that indicating “access”
on the map would provide meaningful information, as access to our Geysers
facilities is no different from access to any of our other natural gas-fired
facilities. In that regard, we note that, in addition to providing
information on the location of each of our facilities, we disclosed in our 2007
Form 10-K that, under our geothermal leases, we have been granted “the exclusive
right to drill for, produce and sell geothermal resources from these properties
and the right to use the surface for all related purposes,” which related
purposes includes access to the properties. Additionally, as set
forth in our response to Comment 2, we also propose to provide further
information in narrative form with respect to our Geysers leases.
Description of power
generation facilities, page 12
|
|
2.
|
We
note you have acquired leases for your geothermal power
facilities. Please disclose the following information
concerning your properties, grouping and summarizing them as may be
appropriate:
|
|
|
·
|
A
description of all interests in your properties, including the terms of
all underlying agreements.
|
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 3 of
22
|
|
·
|
The
basis and duration of your claims or leases, mineral rights, surface
rights, claims and/or concessions.
|
|
|
·
|
An
indication of the type of claim or concession such as placer or lode,
mineral lease or land grant, exploration or exploitation, whether the
mining claims are State or Federal mining claims, mining leases, or mining
concessions.
|
|
|
·
|
The
conditions that must be met to retain your claims or leases, including
quantification and timing of all necessary
payments.
|
|
|
·
|
The
area of your claims or leases, either in hectares or
acres.
|
Please
ensure that you fully discuss the material terms of the land or mineral rights
securing agreements, as required under paragraph (b)(2) of Industry Guide
7.
Response:
We
believe our disclosures, included on pages 12 and 13 of our 2007 Form 10-K,
describing the material rights related to our leased geothermal properties, were
adequate and appropriate based upon the overall significance of our Geyser’s
assets to the Company as a whole and to our West segment. As no
particular lease is individually material, and individual descriptions of each
of the more than 100 leases would not meaningfully add to investors’
understanding of our rights with respect to these properties, the lease
descriptions were grouped so as to provide an understanding of our material
rights. However, we propose to expand the description of our
leases similar to that set forth below (tracked to show changes) in our future
Form 10-K filings:
We
currently lease the geothermal steam fields from which we
extract steam for our geothermal power generation facilities. We have leasehold
mineral interests in 107 leases comprising approximately 27,700 acres of
federal, state and private geothermal resource lands in the Geysers region in
northern California. Our
leases cover one contiguous area of property that comprises approximately 40
square miles in the northwest corner of Sonoma county
and southeastern corner of Lake county in northern California. The
approximate breakout by volume of steam removed under the above leases for the
year ended 2008 (2007 data listed
below) is:
|
|
·
|
31%
related to leases with the Federal Government via the Bureau of Land
Management,
|
|
|
·
|
28%
related to leases with the California State Lands Commission,
and
|
|
|
·
|
41%
related to leases with private
landowners/leaseholders
|
In
general, our
geothermal leases grant us
the exclusive right to drill for, produce and sell geothermal resources
from these properties and the right to use the surface for all related purposes.
Each lease requires the payment of annual rent until commercial quantities
of
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 4 of
22
geothermal
resources are established. After such time, the leases require the payment of
minimum advance royalties or other payments until production commences, at which
time production royalties are payable on a monthly
basis from 10-31 days (depending upon the lease terms) following the close of
the production month. Such royalties and other payments are
payable to landowners, state and federal agencies and others, and vary widely as
to the particular lease. In
general, royalties payable are calculated based upon a percentage of total gross
revenue received by us associated with our geothermal leases. Each lease’s
royalty calculation is based upon its percentage of revenue as calculated by its
steam generated to the total steam generated by the Geysers Assets as
a whole.
Our
geothermal leases are generally for initial terms varying from 10 to 20 years or
for so long as geothermal resources are produced and sold. A
few of our geothermal leases were signed in excess of 30 years
ago.
In
addition, we hold 41 geothermal
leases comprising approximately 46,400 acres of federal geothermal
resource lands in the
Glass Mountain and
Medicine Lake areas in
northern California, which is
separate from the Geysers region. Four test
production wells were drilled
prior to our acquisition and we have drilled one test well, which produced
commercial quantities of steam during flow tests at our
Glass Mountain leases. However, the properties
subject to these leases have not been developed and are not producing
properties. We have capitalized the costs associated
with our test well; however, there can be no assurance that these leases will
ultimately be developed. See Note 15 of the Notes to Consolidated Financial
Statements for a description of litigation relating to our Glass Mountain area
leases.
Our
federal leases are,
in general, for an initial 10-year
period with renewal clauses for an additional 40 years for a maximum of 50
years. The
50-year term expires in 2024 for the majority of our federal
leases. However, our
federal leases allow for a preferential right to renewal for a second 40-year
term on such terms and conditions as the lessor deems appropriate if, at the end
of the initial 40-year term, geothermal steam is being produced or utilized in
commercial quantities. The
majority of our other leases run through the economic life of the
Geysers Assets and
provide
for renewals so
long as geothermal resources are being produced or utilized, or are capable of
being produced or utilized, in commercial quantities from the leased land or
from land unitized with the leased land. Although we believe that we will be
able to renew our leases through the economic life of the Geysers Assets
on
terms that are acceptable to us, it is possible that certain of our leases may
not be renewed, or may be renewable only on less favorable
terms.
We
do not look to ¶(b)(2) of Industry Guide 7 for mining operations as we primarily
analogize our operations and related accounting to oil and gas guidance, which
is further discussed in our responses to Comments 3, 4, 10 and 17 below;
however, we believe that the proposed descriptions above adequately disclose the
material terms and conditions of our geothermal leases.
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 5 of
22
Risk factors, page
35
|
|
3.
|
We
note you state your geothermal energy reserves may not be adequate for
your geothermal operations. Please disclose your proven and
probable geothermal energy reserves, state your current estimate of the
expected duration of economic power generation, the estimated rate of
decline in productivity and/or utilization. Please note
geothermal reserves are specifically excluded from oil and gas producing
activities under Rule 4-10 of Regulation
S-X.
|
Response:
As
the Staff has noted in this Comment, geothermal reserves are specifically
excluded under the requirements of Rule 4-10 of Regulation
S-X. Accordingly, we do not present geothermal reserves.
We
understand that there are differences between oil and gas and geothermal
activities. In particular, unlike oil and gas (or mining) activities,
where the material is extracted and irrevocably depleted, the steam reservoir
from which we capture steam to produce energy is, to some extent, replenished by
us through steam condensate and the injection of reclaimed waste-water directly
into the steam reservoir. Accordingly, we do not believe providing a
“proven” reserve number would be appropriate under the circumstances as these
are expected to change based upon future levels of reinjection and reservoir
replenishment activities. We believe our description and disclosure
related to the economic life of our geothermal resources is adequately explained
on page 12 of our 2007 Form 10-K, which states:
Geothermal
energy is considered a renewable energy because the steam harnessed to power our
turbines is produced inside the Earth and does not require burning fuel to
generate electricity. The extracted steam is also partially replenished by the
injection of condensate associated with the steam extracted to generate
electricity. We also inject clean, reclaimed waste-water from the City of Santa
Rosa Recharge Project and from Lake County through injection wells, which serves
to slow the natural depletion of our geothermal reservoirs. We expect the
injection projects to extend the useful life of this resource and help to
maintain the output of our geothermal resources and power plants.
Upon
review of your comment above, we propose to expand the disclosure in future Form
10-K filings to better explain the economic life of our geothermal assets,
particularly, in relation to the estimated useful life of the steam reservoir
based upon our planned levels of re-injection and reservoir replenishment
activities. We have included this proposed disclosure for future Form
10-K filings in our response to Comment 15 as the determination of our reserves
includes reserve studies.
|
|
4.
|
Please
forward to our engineer as supplemental information, and not as part of
your filing, your information that establishes the legal, technical, and
economic feasibility of
|
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 6 of
22
your
materials designated as reserves, as required by Section C of Industry Guide 7
or Exchange Act Rule 12b-4. The information requested includes, but
is not limited to:
|
|
·
|
Property
and geologic maps
|
|
|
·
|
Description
of your sampling and assaying
procedures
|
|
|
·
|
Drill-hole
maps showing drill intercepts
|
|
|
·
|
Representative
geologic cross-sections and drill
logs
|
|
|
·
|
Description
and examples of your cut-off calculation
procedures
|
|
|
·
|
Cutoff
grades used for each category of your reserves and
resources
|
|
|
·
|
Justifications
for the drill hole spacing used to classify and segregate proven and
probable reserves
|
|
|
·
|
A
detailed description of your procedures for estimating
reserves
|
|
|
·
|
Copies
of any pertinent engineering or geological reports, and executive
summaries of feasibility studies or mine plans which including the cash
flow analyses
|
|
|
·
|
A
detailed permitting and government approval schedule for the project,
particularly identifying the primary environmental or construction
approval(s) and your current location on that
schedule.
|
Response:
We
are providing the applicable materials requested in a supplemental response to
the Staff under separate cover requesting confidential treatment pursuant to the
provisions of 17 C.F.R. Sec. 200.83.
Item 7. Management’s
Discussion and Analysis
Commodity Margin by Segment,
page 48
|
|
5.
|
We
note your presentation and discussion of segment commodity margin in
MD&A on pages 48 and 54. As such, we believe you should
revise either to (1) present the SFAS 131 required disclosures or (2)
include a cross reference in this section to segment footnote 16 in the
financial statements. We refer you to the guidance under FAQ
Regarding the Use of Non-GAAP Financial Measures Question No.
19.
|
Response:
We
agree and propose to include a cross reference to our segment footnote included
in the notes to consolidated financial statements in our future reports on Form
10-K and Form 10-Q, as applicable.
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 7 of 22
Capital Spending and Project
Financing, page 61
|
|
6.
|
Please
revise the first paragraph of this subsection to discuss in dollar terms
the estimated cost of the Russell City Energy Center
project.
|
Response:
For
the reasons described below, we respectfully submit that the estimated cost of
the Russell City Energy Center project (“Russell City” or the “Russell City
project”) represents confidential commercial or financial information the
disclosure of which would result in substantial competitive harm to the
Company. As a result, we respectfully submit that such information is
not required to be disclosed.
Under
Securities Act Rule 406 and Exchange Act Rule 24b-2, the tests for evaluating a
confidential treatment request derive their standard for withholding information
from the Freedom of Information Act (“FOIA”). Courts
have interpreted the confidentiality standard under FOIA to protect as
confidential commercial or financial information including financial
projections, the disclosure of which “would provide competitors with valuable
insights into the company’s operations, give competitors pricing advantages over
the company, or unfairly advantage competitors in future business negotiations.”
People for the Ethical
Treatment of Animals v. United States Department of
Agriculture, 2005 WL 1241141 (D.D.C. 2005) at *7 (citing National Parks &
Conservation Assoc. v. Kleppe, 547 F.2d 673,
684 (D.C. Cir. 1976)). The types of information that courts have held
are within the scope of the exemption are broad and include, without limitation:
information regarding the method of pricing and cost increases; contractual
pricing provisions; sales and profit data; and business sales statistics, such
as total net sales, total costs and expenses, operating costs, gross sales and
renegotiable sales. Burke Energy Corp. v.
Department of Energy
for the United States of America, 583 F. Supp. 507, 511 (D. Kan. 1984)
(citations omitted); see also Herrick v. Garvey, 200 F. Supp.
2d 1321, judgment aff’d, 298 F.3d 1184 (10th. Cir. 2002) (confidential treatment
accorded to blueprints detailing product manufacturing and design information),
National Broadcasting
Co. v. U.S.
Small Business Admin., 836 F. Supp. 121 (S.D.N.Y. 1993) (confidential
treatment accorded to documents containing information relevant to a company’s
financial status and/or the financing of the company). As the
Division of Corporation Finance noted in Staff Legal Bulletin No. 1,
“[s]ometimes disclosure of information required by the regulations can adversely
affect a company’s business and financial condition because of the competitive
harm that could result from the disclosure,” in which case even information
required to be disclosed by the SEC’s regulations can be deemed
confidential. “Confidential Treatment Requests,” Division of
Corporation Finance Staff Legal Bulletin No. 1A, Fed. Sec. L. Rep. (CCH) 60,001
(February 28, 1997 (Addendum Included: Ju1y 11, 2001)).1
Applying
these standards to the request for disclosure regarding the estimated costs to
complete the Russell City project, we respectfully submit that disclosure of our
projected costs would lead
|
1
|
The
Company acknowledges that the statements in Staff legal bulletins do not
constitute rules, regulations or statements of the SEC and are not legally
binding.
|
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page
8 of 22
to
competitive harm to the Company because (1) it would provide potential
counterparties an unfair advantage in negotiations with respect to project
agreements; (2) it would undermine the Company’s position and ability to
negotiate the most favorable terms for the project financing necessary to
construct the facility; (3) the Company does not publicly disclose
forward-looking information relating to expected costs of development projects
prior to entering into applicable project documents and obtaining project
financing; and (4) the estimated costs constitute proprietary information based
on a number of possible project and financing arrangements the disclosure of
which would not only provide the Company’s potential project or finance
counterparties with an unfair advantage in negotiations but provide the
Company’s competitors with a competitive advantage in the development,
construction and acquisition of competing power project assets.
The
Russell City project is our only consolidated project in active
development. Construction is anticipated to begin once all permits
and other required approvals are final and non-appealable, and project financing
has closed. Upon completion, this project would bring on line approximately 362
MW of net interest baseload capacity (390 MW with peaking capacity) representing
our 65% share.
As
indicated, we have not yet obtained project financing for this
project. Our ability to obtain project financing, the amount of
project financing required, the pricing terms including interest rates, and
other terms (maturity, defaults, covenants, security arrangements, etc.) of any
project financing are dependent upon the terms of the underlying project and
construction agreements (including without limitation construction, turbine,
operation and maintenance, long-term maintenance, project management, power
purchase, interconnection, offtake, pipeline and gas transportation
arrangements) that are to a large extent unknown as we have not yet completed
negotiations on, or entered into, the array of major project documents that will
be required before financing can be obtained or construction begun.
Our
expected costs to complete the Russell City project will determine the amount of
project financing required, as we expect to use project financing to fund a
significant portion of these costs. The total expected costs are
driven to a large extent by the terms we are able to negotiate with
counterparties to our underlying project agreements. While we model
an array of potential scenarios, disclosing the expected costs would signal to
counterparties a base case scenario from which they could begin negotiations,
placing the Company at a disadvantage and preventing the Company from being able
to negotiate the most favorable terms for such agreement. This would
impact the amount of financing necessary, and, to the extent that the project
agreements were less favorable than they otherwise would have been, will not
only drive up the expected principal amount of the financing, but affect the
other terms of the financing including the structure, interest or other
payments, timing of payments, security arrangements and covenant and default
provisions, among other things. In addition, disclosing our estimated
costs to completion at this stage would provide our competitors with an
advantage, particularly in the California market where the Russell City project
is to be constructed. Our competitors could use the information to
underbid us, or to seek to develop or construct competing generation facilities
at a lower cost than they
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 9 of 22
would
otherwise have been able, reducing our ability to obtain the required permits
and other approvals necessary to construct the Russell City project or reducing
the comparative economics and demand for the energy to be produced by the
Russell City project.
Another
test for whether information is confidential is whether the information is of
the type that would not customarily be released to the public by the person from
whom it was obtained. Sterling Drug, Inc.
v. Federal Trade
Commission, 450 F.2d 698, 709 (D.C. Cir. 1971); Board of Trade of
Chicago v. Commodity Futures Trading
Commission, 627 F.2d 392, 404 (D.C. Cir. 1980). The Company
has not publicly released information regarding its estimated costs to complete
the Russell City project and would not customarily publicly release information
regarding its costs to construct a facility for the reasons noted
herein.
Additionally,
the Company has not historically publicly disclosed forward-looking guidance or
made other prospective disclosure with respect to the potential costs to
complete individual projects in development. The Company has adopted
this approach based on its belief that such guidance does not serve the best
interests of the Company or its stockholders. We believe that our
decision not to provide such estimates allows us to maintain a fair position in
negotiations so that we may achieve the most favorable terms on project and
financing agreements that allow us to move our projects in development to the
construction stage. We respectfully submit that disclosure of this
confidential commercial and financial information would put us at a competitive
disadvantage in such negotiations, increasing the costs to the Company and
potentially delaying or otherwise obstructing project construction.
We
note that the information regarding potential costs to complete the Russell City
project are not expected to be material to the Company. The Company
currently operates more than 80 generating facilities capable of producing
almost 24,000 megawatts of electricity. At June 30, 2008, the
Company had more than $22.6 billion in total assets including more than $8.3
billion in total current assets, and carried approximately $10.4 billion in
debt. Russell City, which is expected to generate 390 megawatts
(representing the Company’s 65% interest), will not represent a material change
to the Company’s overall production capacity or its assets, and is not expected
to result in a material debt obligation. Additionally, this project
has not received all of the required regulatory permits and approvals. If
the Company does not receive these, the Company could delay construction or
otherwise suspend development activities. Accordingly, disclosing the
Company’s expected costs at this time would not provide investors with material
information or change the total mix of information available to
investors.
When the
major underlying project documents have been executed and project financing is
in place, the Company expects to disclose the amount of such project
financing. For example, see the Company’s disclosures regarding its
project financing facilities in Note 8 of the Notes to Consolidated Financial
Statements included in the 2007 Form 10-K. Thus, we do not seek to
keep all information regarding our costs permanently confidential, but would
provide the information regarding our project financing and, to the extent
material, other costs or contributions, if any, that are not funded with project
financing at a later time when the disclosure will not cause the Company
competitive harm.
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 10 of 22
For
the reasons discussed above, the Company believes that the information regarding
expected cost to complete the Russell City project is confidential and should
not be disclosed.
Item 9A Controls and
Procedures
Disclosure Controls and
Procedures, page 80
|
|
7.
|
We
note your statement that disclosure controls and procedures were effective
at the reasonable assurance level. Please explain and revise in
future filings, if true, that your disclosure controls and procedures are
designed to provide reasonable assurance of achieving their
objective. In the alternative, remove the reference to the
level of assurance of your disclosure controls and
procedures. Please refer to Section II.F.4, SEC Release No.
33-8238 for guidance.
|
Response:
We
will remove the reference to the level of assurance of our disclosure controls
and procedures in our future Form 10-K and Form 10-Q filings.
Item 13. Certain
Relationships and Related Transaction, and Director Independence, page
114
|
|
8.
|
Please
revise to describe your policies and procedures for the review, approval,
or ratification of any transaction required to be reported under Item
404(a) of Regulation S-K. Please see Item 404(b) of Regulation
S-K.
|
Response:
A
description of the Company’s policies and procedures with respect to the
reporting and approval of related party transactions as required by Item 404(b)
of Regulation S-K was included in the 2007 Form 10-K under Item 10. “Directors
and Executive Officers of the Registrant — Code of Conduct.” There were no
transactions required to be reported under Item 404(b)(2). We
agree that this information should also have been included as part of
Item 13, and propose that, in future filings, we will ensure that this
information be included under Item 13 directly or that Item 13 include a
cross-reference to clearly identify where the information may be
found.
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 11 of 22
Financial Statements and
Notes
2. Summary of Significant
Accounting Policies
Basis of Presentation and
Principles of Consolidation, page 151
|
|
9.
|
We
note your disclosures that “[o]n May 3, 2007, OMEC, an indirectly
wholly owned subsidiary and the owner of the Otay Mesa Energy Center,
entered into a 10-year tolling agreement with SDG&E…provides for a put
option for OMEC to sell and a call option by SDG&E to buy, the Otay
Mesa facility at the end of the tolling agreement.” Advise us and disclose
in more detail the significant terms of the tolling agreement, and the put
and call options. Addressing relevant GAAP literature, explain
to us how you determined that deconsolidation of the entity is appropriate
effective the second quarter of
2007.
|
Response:
As
OMEC is deconsolidated and does not constitute a significant subsidiary,
additional discussion of the significant terms of the tolling agreement would
not meaningfully add to investors’ understanding of our operations and revenue
recognition and are not included. Further discussion of the
significant terms of the put and call options follows in our response addressing
how we determined deconsolidation was appropriate.
Our
analysis that deconsolidation was appropriate in the second quarter of 2007 is
based upon application of FIN 46(R) “Consolidation of Variable Interest Entities
– An Interpretation of ARB 51.”
Concurrent with obtaining $377
million in project financing in May 2007, we entered into a ten-year tolling agreement with San
Diego Gas & Electric (“SDG&E”) for the full output of OMEC and we also
entered into a ground sublease easement with SDG&E, which provides for a put
option by us to sell and a call option for SDG&E to buy OMEC. The
new contracts between OMEC and SDG&E were determined to trigger a
reassessment of the primary beneficiary of OMEC in accordance with the
requirements of FIN 46R. We analyzed the criteria to determine the primary
beneficiary in a two step process:
Step
1 – Analyze the risks of the entity and to which party the primary risk of loss
and potential for reward are passed along to. We determined the most
significant risk was price risk (change in fair value).
Step
2 – Determine the purpose(s) for which the entity was created and determine the
variability the entity is designed to create and pass along to its interest
holders.
In
doing so we determined:
|
|
·
|
The primary purpose for which
the entity was created was to provide SDG&E with use of the property
for ten years with substantially all of the rights and obligations of
ownership.
|
|
|
·
|
The combination put/call
option transfers a significant amount of the risk and reward of ownership
to SDG&E. SDG&E will benefit from increases in the property value
above
|
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 12 of 22
$377
million and will be exposed to loss in value below $280 million. Calpine retains
the risk of change in value between $280 million and $377 million.
As
a result of your comment requesting more detailed disclosure, we propose to
include disclosure similar to that set forth below (tracked to show changes) in
future Forms 10-Q and 10-K:
We
deconsolidated OMEC during the second quarter of 2007 as a result of a 10-year
tolling agreement we entered into with SDG&E and assignment of rights under
an existing ground lease and ground sublease and easement agreement to SDG&E
in May 2007, which, among other things, provides for a put option by OMEC
to sell, and a call option by SDG&E to buy, the Otay Mesa facility at the
end of the tolling agreement. These
new
contracts resulted in a reconsideration under FIN 46(R) to determine if
OMEC constituted a variable interest entity
and if we should continue to consolidate OMEC. Because
the put and call options effectively
create a minimum floor and a maximum ceiling
value to Calpine, the
put and call options absorb the majority of our risk
of loss and potential for reward
related to the property and transfer these to SDG&E. As a result, we
determined
that
we are not OMEC’s primary beneficiary. Accordingly, we
deconsolidated OMEC during the
second quarter
of 2007 and have accounted for our investment in OMEC under the
equity method.
Property, Plant and
Equipment, Net, page 157
|
|
10.
|
We
note your disclosures that you capitalize costs incurred in connection
with the development of geothermal properties in your geothermal
operations. In this regard, please supplementally explain, with
a view toward expanding disclosure, your capitalization policy for
exploration and development costs. In this regard, please
advise whether you have ever incurred exploration costs and if so, how
drilling and any other exploration type costs are treated in your
financial statements. Your policy should be more specific in
describing the nature of each type of costs capitalized in addition to a
discussion of when you begin capitalizing them. Tell us and
consider disclosing such
|
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 13 of 22
costs as
component amounts in a footnote to the financial statements. Cite the
relevant authoritative GAAP literature, or accepted practice, that you relied
upon or analogized to for your accounting. We may have further
comments.
Response:
We
have historically analogized our geothermal accounting to oil and gas
accounting. We purchased the Geysers Assets as a proven steam reservoir and
accounted for the assets under purchase accounting. All well costs
have been capitalized since our purchase date as they have represented new
development or services. Exploration activities are extremely limited
and not material to our overall capital expenditures or our fixed
assets. A total of 4 deep test wells were drilled at Glass Mountain
prior to us acquiring the Glass Mountain leases. Since our
acquisition, we have drilled one deep test well at Glass Mountain in 2001 which
produced economically viable quantities of steam and the well costs were
capitalized. We recorded an impairment charge of approximately $25 million at
December 31, 2005 related to our Glass Mountain leases as part of our
reduction in development activities resulting from filing for Chapter 11
bankruptcy. Immaterial holding costs at Glass Mountain are
expensed.
Our
current capital expenditures at the Geysers Assets are those incurred for proven
reserves and reservoir replenishment (primarily water injection), pipeline and
power generation assets and drilling of “development wells” as all drilling
activity has been performed within the known boundaries of the steam
reservoir. We have capitalized costs incurred during ownership
consisting of additions, repairs or replacements when they appreciably extend
the life, increase the capacity or improve the efficiency or safety of the
property. Such costs are expensed when they do not meet the above
criteria. Our Geyser’s capitalization policy that has been followed
is summarized as follows:
|
|
1.
|
New
equipment – All new projects over $25,000 and identified as “new,” that
is, not replacing any existing equipment already in service at the
Geysers, are capitalized. Examples of new equipment
include:
|
|
|
·
|
A new well, either production
or injection, into a proved area of the
reservoir;
|
|
|
·
|
A new pipeline built to
mitigate “bottlenecking” of steam or to cross-tie existing facilities to
improve flexibility or operational capabilities;
or
|
|
|
·
|
New plant equipment that adds
to existing equipment to mitigate potential risk or to improve efficiency
(for example, the addition of a second vacuum pump to a gas removal system
where only one pump existed
before).
|
|
|
2.
|
Plant
overhauls and well workovers or cleanouts – The work associated
with all power plant overhauls, which generally occur on a five year
cycle, is expensed. In addition, well workovers or cleanouts
are expensed. If a new liner is added to a well where there was
no liner before, we will capitalize the cost of the liner while all of the
rig mobilization costs and drilling costs will be expensed as they are
deemed to be part of the
|
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 14 of 22
cleanout. The
new liner is added to the capital base because we are adding an asset that did
not exist before. The new asset (the liner) improves the efficiency
and life of the well.
|
|
3.
|
Costs
associated with changes in functionality that leverage off of existing
assets are capitalized. The two primary examples
are:
|
|
|
·
|
Converting an existing
production well into an injection well, which adds new equipment (a
slotted liner) to the well to change its functionality. A
conversion of a producing well to an injection well is normally performed
as it is significantly cheaper than drilling a new injection
well.
|
|
|
·
|
An existing production well is
“forked” to increase production. In this example we will use an
existing well to create another leg via directional drilling to tap into a
non-producing area of the geothermal
resource.
|
|
|
4.
|
Safety
and environmental concerns or requirements – Costs associated with changes
that are made purely to meet new environmental or safety regulations the
cost of the project are capitalized. Examples
include:
|
|
|
·
|
Installing eye wash stations
to satisfy safety
requirements.
|
|
|
·
|
Building a sound barrier
around a pump or a blower to mitigate noise
exposure.
|
|
|
·
|
Building an enclosure around a
control panel to protect the panel and reduce exposure to high noise
levels.
|
|
|
·
|
Building a fish ladder in a
creek to satisfy environmental
regulations.
|
|
|
5.
|
Existing
equipment replacements – Because the overall output of the Geysers is very
seldom impacted by the replacement of old equipment, the replacement is
usually expensed if it is performing the same function, even if it is
doing the job more efficiently or at a cost savings. There is an exception
where the equipment removed is refurbished and retained as a capital
spare. The repair costs are expensed and charged as a plant
operating expense; however, this does result in two assets that can be
clearly identified on the books, and the cost of the new asset will be
capitalized.
|
We
have retained our geothermal rights to the Glass Mountain leases which is an
undeveloped steam field. We have not yet determined whether
development of these assets is economically feasible. If we decide to
develop this field, we expect to capitalize these expenditures, in accordance
with our capitalization policy discussed above.
Because
we are not actively pursuing exploration and development into unproven
geothermal fields, we do not have any exploration costs. Our net book
value of our Geysers property, plant and equipment represents only 5.5% our
consolidated total and no separate disclosure is planned. Should
these costs become significant in the future, we will disclose these in our
future filings as appropriate.
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 15 of
22
In
determining our capitalization policies at the Geysers, we have historically
applied the guidance under oil and gas accounting. Our application of this
guidance has been based upon the following:
|
|
·
|
There are no
geothermal-specific industry standards or
guidance.
|
|
|
·
|
The technology used to drill
wells and collect the steam is substantially the same as oil and gas
technology. In fact, the third parties we use to drill new
wells and overhaul or modify our existing wells are oil and gas drilling
companies.
|
|
|
·
|
Our analyses and reserve
studies of the steam reservoir are based upon oil and gas technology and
techniques.
|
16. Segment and Significant
Customer Information, page 205
|
|
11.
|
Please
provide a reconciliation of the segments’ assets to the consolidated
assets. Reference is made to paragraph 32c of SFAS
131.
|
Response:
Our
management reporting system does not generate asset information or capital
expenditure information by segment to present to management and is not reviewed
by or provided to our chief operating decision maker. Based upon our
review of SFAS No. 131, we determined that only items included in our management
reporting are required to be reported under the rules and we are not obligated
under SFAS No. 131 to create information that otherwise does not exist in our
management reporting system.
|
|
12.
|
Please
disclose the segments’ capital expenditures in accordance with paragraph
28b of SFAS 131 or advise us why you are not required to do
so.
|
Response:
As
discussed in our response to Comment 11 above, our management reporting system
does not generate asset information, including capital expenditures, by segment,
nor does our chief operating decision maker review this
information. Based upon our review of SFAS 131, we determined that we
are not required to present this information.
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 16 of 22
Form 10-Q for the Quarterly
Period Ended June 30, 2008
Financial Statements and
Notes
1. Basis of Presentation and
Summary of Significant Accounting Policies
Deconsolidations, page
7
|
|
13.
|
We
note your deconsolidation of RockGen during the first quarter of 2008
resulting from the call option to absorb the majority of expected losses
and residual returns from the entity such that you are not the primary
beneficiary. In that regard, tell us and disclose in more
detail the option terms that form the basis behind your conclusion that
you are not the primary
beneficiary.
|
Response:
Our
analysis that deconsolidation of RockGen Energy Center (“RockGen”) was
appropriate based upon the following:
The
purchase of the RockGen assets in January 2008 resulted in a
reconsideration of the primary beneficiary of RockGen, similar to the
reconsideration triggered with respect to OMEC, as discussed in our response to
Comment 9. Our power purchase sales agreement (“PPA”) with Wisconsin Power &
Light ("WP&L") contains a call option. Under the terms of the
call option, WP&L may purchase the plant for a price of $141 million at
May 31, 2009 provided 180 days prior written notice of exercise of the call
option is given. Similar to the analysis conducted with respect to
OMEC, we evaluated the call feature in the WP&L PPA with RockGen under FSP
FIN 46(R)-6 in order to determine the primary beneficiary. Based on this
analysis, we determined that the call option provided WP&L with the risks
and rewards of ownership as they are the primary entity exposed to potential
changes in value of the plant.
We
propose to include disclosure similar to that set forth below (tracked to show
changes from our prior filings) in future filings on Forms 10-Q and
10-K:
Our
purchase of the RockGen assets during
the first quarter of 2008 terminated the sale-leaseback agreement with CIT
Group, which required
reconsideration under FIN 46(R) to determine RockGen's primary
beneficiary. Our
PPA with WP&L contains a call option which allows
WP&L and related parties to purchase RockGen on May 31, 2009 at a fixed
price, provided they give 180 days prior written notice. The call option effectively
creates a ceiling value for Calpine and absorbs the majority of our
potential for expected
residual returns from the entity, transferring the potential
risks and rewards
to
WP&L. As a result, we
determined that we are not RockGen’s primary beneficiary.
Accordingly, we deconsolidated RockGen during the first quarter of 2008,
and our investment in RockGen is accounted for under the equity method. If
written notice is not received in compliance with the 180 day requirement and
the call option expires unexercised, we expect that the
expiration of the call option will
again trigger reconsideration
under FIN 46(R), at
which time, it
is possible that we
may be required to consolidate RockGen.
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 17 of 22
12. Commitments and
Contingencies
Potential Loss and
Deconsolidation/Sale of Auburndale Power Plant, page 27
|
|
14.
|
We
note that you consolidated Auburndale, a variable interest entity, as of
June 30, 2008. In order to better understand your
accounting, explain to us how you consider paragraph 14 of FIN 46R in
determining that you are the primary beneficiary in consolidating the
entity in light of the fact that Pomifer, an unrelated party, holds a
preferred interest in the entity that entitles Pomifer to 70% of the
entity’s cash distributions through
2013.
|
Response:
On
September 3, 2003, Calpine sold a preferred interest in Auburndale Holdings
LLC to Pomifer Power Funding, LLC (“Pomifer”), a wholly own subsidiary of
ArcLight Energy Partners Fund I, L.P. for $88 million. The preferred interest
entitled Pomifer to approximately 70% of the cash flows in Auburndale Power
Partners LP (“APP”) (which holds the Auburndale power plant) over the priority
repayment period through 2013. After the priority period, Calpine and
Pomifer would split net cash flows from the project 60% - 40%, respectively, for
the remaining life of the partnership.
We
determined the preferred interest met the criteria of a mandatorily redeemable
financial instrument and accordingly classified it as debt under the guidance of
SFAS No. 150, due to the preferential distributions to Pomifer. The
preferential distributions are paid quarterly beginning in November 2003
and total approximately $204.7 million over the priority repayment period with
an effective interest rate, after amortization of deferred financing charges, of
16.8%. Pomifer’s recourse is limited to the net assets of the
entity. We have not guaranteed the payment of these preferential
distributions. Calpine holds the remaining interest in the facility
and continues to provide operations and maintenance services.
The
cost of new construction was lower in 2003 than in current markets such that our
initial analysis of the purchase option and the potential drag along rights were
considered too far in the future to predict with any degree of certainty that
the exercise of the purchase option and drag along rights were likely to
occur.
Our
initial projections and analysis in 2003 determined that we expected to repay
and satisfy Pomifer’s preferred interest in accordance with the preferred
interest terms. Additionally, our initial projections showed greater
returns in the latter years of Auburndale’s life and the remaining residual cash
flows past 2013 were much greater to Calpine than to Pomifer over the life of
the project and showed that Calpine had the majority of the expected residual
risk of returns. Accordingly, we determined consolidation was
appropriate.
On
August 21, 2008, Pomifer exercised its right to purchase additional
interest in the cash flows of Auburndale. The purchase of additional
interest was determined to require a reconsideration under FIN 46(R) similar to
OMEC and RockGen discussed above. We are performing a FIN
46
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 18 of
22
analysis
in conjunction with the preparation of our financial statements and Form 10-Q
for the period ending September 30, 2008 to determine if we should
deconsolidate Auburndale.
|
|
15.
|
Please
disclose whether or not a reserve audit has been performed over the last
three years.
|
Response:
Note
that we have assumed that this comment relates to our geothermal reserves, and
to our annual (Form 10-K) rather than quarterly (Form 10-Q)
disclosures. With respect to our geothermal reserves, we propose to
add disclosure similar to the below in our future Form 10-K filings to describe
our reserve studies and to provide the additional disclosure as noted in our
response to Comment 3 above:
We
periodically obtain independent geothermal studies to help us assess the
economic life of our geothermal reserves. Our most recent independent
geothermal reserve study was conducted in 2006. Our evaluation of the
reserve study indicated that the Geysers Assets should continue to supply
sufficient steam to generate positive cash flows through
2050. Significant assumptions used in the study and our evaluation
are as follows:
|
|
·
|
The
study defined “proved reserves” as those quantities of geothermal energy
which, by analysis of geological and engineering data, can be estimated
with reasonable certainty to be commercially recoverable, from a given
date forward, from known reservoirs and under current economic conditions,
operating methods, and government regulations. The “given date forward”
was “Calpine’s schedule of development, operation and investment over the
period 2006 to 2050.”
|
|
|
·
|
Our
evaluation of the study concluded that, based upon our planned level of
continued capital expenditures and reservoir replenishment activities,
generation would decline to about 580 MW by 2020, reaching about 450 MW in
2050. This forecasted rate of decline includes the impact of water
injection contracts, current decline rates and expected production and
operating costs going forward.
|
|
|
16.
|
Green
energy or renewable energy may receive premium pricing compared to
conventional energy sources. Please disclose the average
electrical power pricing received from your geothermal power plants
compared to conventional power generating
activities.
|
Response:
For
the reasons described below, we respectfully submit that the information
requested represents confidential commercial or financial information the
disclosure of which would result
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 19 of 22
in
substantial competitive harm to the Company. As a result, we
respectfully submit that such information is not required to be
disclosed.
The
tests for evaluating a confidential treatment request are discussed above in our
response to Comment 6. As noted, courts have interpreted the
confidentiality standard under FOIA to uphold confidential treatment of
commercial or financial information including financial projections where the
disclosure of such information “would provide competitors with valuable insights
into the company’s operations, give competitors pricing advantages over the
company, or unfairly advantage competitors in future business
negotiations.” People for the Ethical
Treatment of Animals v. United States Department of
Agriculture, 2005 WL 1241141 (D.D.C. 2005) at *7 (citing National Parks &
Conservation Assoc. v. Kleppe, 547 F.2d 673,
684 (D.C. Cir. 1976)). The information requested here, confidential
pricing information, is squarely within the category of confidential commercial
or financial information and is routinely accorded confidential treatment – see,
for example, Burke
Energy Corp., 583 F. Supp. at 511-12, where the court found that, among
other things, “... contractual pricing provisions, … base price of product
obtained from a particular plant, … a ceiling price determination … bonus
prices, … overcharge amounts, … pricing and product conversion factors, …
substitute selling price[s], … base prices, … reference prices, [and] … the
method of pricing and cost increases … are confidential because … that is
clearly the type of information a corporation would not customarily release to
the public,” the disclosure of which “would very likely cause substantial harm
to the competitive position” of the corporation. Id. at 112; see also
Sterling Drug,
Inc. v. Federal
Trade Commission, 450 F.2d 698, 709 (D.C. Cir. 1971) (sales and profit
data, breakdowns of sales, market share data, and confidential bid amounts) and
Fisher v. Renegotiation Board,
355 F. Supp. 1171, 1174 (D.D.C. 1973) (business sales statistics including total
net sales, total costs and expenses, operating costs, gross sales, and
renegotiable sales), both cited by Burke Energy
Corp.
The
renewable energy sector is highly competitive and currently poised for growth as
government initiatives to reduce greenhouse gas emissions and dependence on
foreign fossil fuel products continue to be implemented. The Company
currently competes with well established companies in this market space and
expects to encounter additional competition from new entrants as the sector
continues to grow and develop. Many of the Company’s current
competitors in the renewable energy sector are privately held and therefore are
not required to publicly report any information about their
operations. We expect that new entrants into this sector also will
for the most part be private companies, at least in the near
term. Requiring the Company to disclose the prices it receives for
its geothermal production would thus put the Company at a serious disadvantage
by enabling competitors to either underbid the Company or to seek to obtain
higher prices for themselves than they would otherwise be able to
negotiate. In addition, providing this information to the Company’s
potential customers for geothermal power would afford them an unfair advantage
in future negotiations, essentially setting a cap on pricing, while at the same
time reducing the Company’s ability to negotiate for better pricing with its
current customers and putting pressure on current customers to reduce the
pricing or to purchase electricity from sources other than the
Company.
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 20 of
22
The
information requested has never been made public by the Company and has
historically been viewed by the Company as proprietary and
confidential. Providing this information to the general public and,
as a result, to the Company’s competitors and customers, would result in
disclosure of sensitive information relative to the Company that is not
generally disclosed, providing competitors and customers an unfair advantage in
negotiations. As described above, this would cause considerable harm
to the Company’s ability to negotiate for premium pricing and to compete
effectively in the renewables sector, to the detriment of the Company and its
shareholders. Thus, as in Burke Energy Corp.,
disclosure of the pricing information would cause the Company substantial harm
in that “... the disclosure would permit competitors to acquire private
information about [the corporation’s] pricing policies; would enable competitors
to gain otherwise confidential information about [the corporation’s] financial
situation; would enable competitors to solicit [the corporation’s] customers
with competitive arrangements; and would without question adversely affect [the
corporation] in many ways.” 583 F. Supp. at 512.
We
note that information regarding the Company’s commodity margin (essentially a
measure of the difference between the price received by the Company for
electricity and its fuel costs)2 by segment is provided. The
Geysers, which constitute our only producing geothermal resource, are included
in the West segment. Thus, the effect on our commodity margin as a
result of the revenues from geothermal sources is generally
disclosed. We do not believe the additional information, namely the
difference between the prices for the geothermal production versus the prices we
receive for production by our natural gas-fired facilities (or other
“conventional power generating activities” such as oil, gas, coal or other
production in which the Company is not engaged) would materially add to an
investor’s understanding of the Company’s business or operations or change the
total mix of information that is available to investors.
Accordingly,
for the reasons discussed above, the Company believes that the information
regarding the average pricing received for geothermal production compared to
conventional power generating activities is confidential and should not be
disclosed.
|
|
17.
|
Please
describe your policy for amortizing capital expenditures for your
geothermal projects and whether you use your geothermal reserve estimates
as a basis for this calculation. Do you amortize using units of
production or an estimated project
life?
|
Response:
For
depreciation calculations, the Geysers uses units-of-production depreciation in
recognizing yearly depreciation. The units-of-production depreciation
rate is calculated using a depreciable base of the net book value of the Geysers
assets plus the expected future capital expenditures of
|
2
|
Commodity
margin is defined by the Company as a non-GAAP financial measure that
includes electricity and steam revenues, hedging and optimization
activities, renewable energy credit revenue, transmission revenue and
expenses, and fuel and purchased energy expenses, but excludes
mark-to-market activity and other service
revenues.
|
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page
21 of 22
the
economic life of the geothermal reserves (2050). The rate of
depreciation per megawatt hour is determined by dividing the depreciable base by
total expected future generation (estimated units of proved
reserves). Because our geothermal properties extract steam from one
reservoir, we aggregate our geothermal assets into one depreciable
basis.
We
use a combination of Decline Curve Analysis and Three Dimensional Numerical
Modeling. Our Numerical Model is a proprietary computer program that
performs approximate solutions to matrices of partial differential equations
that describe the characteristics of the steam reservoir. The model
is also adjusted to account for 20 plus years of actual production history. When
simulation of the historical production time period is modeled within a
reasonable fit of the actual production that has been observed, the model is run
to forecast the future production. We believe that this process is
key to evaluating the future production from the Geysers.
Our
Geysers depreciation model is revised every year to include updates to
anticipated future capital expenditures and estimated proved
reserves. The new amortization rate is then applied to actual
production to determine depreciation expense. We account for those revisions
prospectively as changes in accounting estimates.
Mr. H.
Christopher Owings
United
States Securities and Exchange Commission
October
24, 2008
Page 22 of
22
*****
As
requested in the comment letter, we hereby acknowledge that:
|
|
·
|
The
Company is responsible for the adequacy and accuracy of the disclosure in
this filing;
|
|
|
·
|
Staff
comments or changes to disclosure in response to Staff comments do not
foreclose the Commission from taking any action with respect to the
filing; and
|
|
|
·
|
The
Company may not assert Staff comments as a defense in any proceeding
initiated by the Commission or any under person under the federal
securities laws of the United
States.
|
We
appreciate the assistance the Staff has provided with its comments on the above
referenced documents as originally filed, and we will be pleased to respond
promptly to any requests for additional information. My phone number
is (713) 570-4654 and my fax number is (713) 353-9167.
|
|
Sincerely,:
|
|
|
|
|
|
|
|
|
/s/ Kenneth
A. Graves
|
|
|
Kenneth
A. Graves
|
|
|
Interim
Corporate Controller and
|
|
|
Principal
Accounting Officer
|
|
|
|
|
cc:
|
Mr.
Andrew Mew
|
|
|
Mr.
Scott Stringer
|
|
|
Mr.
Ramin Olsen
|
|
|
(Securities
& Exchange
Commission)
|