Renewable Cost Issues
1. Gathering data on costs of different renewable sources
a. Is there publicly available information that the Board can rely upon? If so, how
can we access and apply the information?
b. Do earlier Board dockets provide useful cost data on renewable energy
projects? If so, which ones and what data?
c. If not, should we require information from all developers/vendors?
d. Confidentiality - should some data be protected? If so, how do other parties
evaluate?
e. Will electric utilities be required to disclose their cost of renewable energy
projects that they construct?
DPS: The law requires the Board to set rates based on the costs and
performance of the various technologies referenced. The Department
recommends that accurate, verifiable and fully supported cost and
performance data from installers doing business in Vermont, supplemented
with publicly available data be provided. The Board should require this
information from individuals wishing to receive the benefits of the feed-in
tariff. Further, since the rates are to be adjusted semiannually, the Board
should require, as a condition of receiving feed-in tariff rates, that system
owners disclose the costs of each system installed on a going forward basis.
This will assist in setting rates in the future.
It is the Department’s position that all data, except for the name of the
purchaser, should not be protected. Further, it is the Department’s position
that any such data filed in support of these rates should be held to the same
standards as required of utilities in their filings. Without a method to test
the veracity of any data received, the Board may not be able to accurately
determine costs and performance of these systems. Should the Board hire a
consultant, as discussed below, it may be possible for that person or firm to
fulfill the role of an intermediary in the data verification process.
If electric utilities develop SPEED projects, their disclosure requirements
should be no different than any other participant. Additionally, they should
disclose these costs in the same manner as required for normal ratemaking
and consistent with normal reporting requirements.
2. Evaluation of data
a. The Board is considering hiring a contractor to assist with data development
and analysis. Are there any issues with this approach?
b. What process should the Board employ to obtain input from
developers/vendors and other stake holders?
c. What is the standard of review that the Board should employ when looking at
cost data? Should the Board only alter the statutory prices if it finds a major difference?
d. How will the Board determine whether new deployment or the pace of new
deployment of renewable projects is occurring as a direct result of the Standard Offer?
DPS: The Department supports the notion of the Board hiring a consultant
to assist in this effort. The utility regulatory staff at both the Board and
Department has little experience in evaluating the costs of these smaller
projects, so additional expertise in this area should prove very helpful.
The Board should employ a combination of processes to obtain input from
vendors and other stake holders. The Board should ask for a filing from
stakeholders of cost and performance data which they feel is representative
of the systems to be installed under this tariff. As discussed above, there
should be opportunity for data verification, both through the Board’s
contractor and through discovery, if necessary. Parties without direct
experience in the installation business should also be allowed to submit data
if they so choose. The Board, through its contractor would be charged with
sorting this data, verifying it, and developing a pro-forma type cost structure
for representative system types.
3. What level of granularity should prices have? One for each type of resource, or
different prices based upon certain characteristics?
a. If we aim for granularity, is there enough data to support each set of prices?
b. What costs, and thus prices, of different capacity sized plans of the different
renewable resources should be addressed?
c. What is the appropriate capacity differentiation?
d. How will the Board determine the price for each type of technology?
DPS: To a large extent, the granularity necessary will hopefully reveal itself
in the data analysis – at least for the generic costs of different system types.
There may be other dimensions of granularity which may make sense based
on other factors such as tax/income characteristics of the project owner or
others. Since the objective is a determination of cost, the Department feels
that value features of different resource types, such as location of a system
relative to transmission deficiencies, performance relative to peak hour
pricing, or system peak coincidence are not appropriate adjustments to make
in determining a rate to be offered. These characteristics may be used to
form a basis for a rate design, however. This idea is discussed more fully
below.
Also important in the determination is the performance of each technology
and each size of the technology.
4. How do we value the tax credits and other support, such as grant programs?
a. What credits and grants are available?
b. Should standard offers differentiate between plants that can and cannot take
advantage of tax credit(s) available?
DPS: In general, the Department feels that representative costs should be
determined based on a well designed system, properly installed in a location
with very supportive resource availability, including transmission. Further,
the cost should assume that an owner takes advantage of all of the available
financial support mechanisms reasonably applicable to representative
projects. To that end, the Department is preparing a list of taxes, tax credits
and grants available to support renewable projects of this nature. Included
will be a summary of the projects funded to date through the clean energy
development fund and the grant support received by those projects. In the
coming weeks, the Department, in conjunction with the Tax Department, will
estimate the impact of these tax credits and grants on the ultimate cost of a
project.
5. How should the Board value the cost of any system impact or facilities or stability
studies required in order to interconnect? In particular, does this create a barrier for
smaller projects?
a. What share of the interconnection costs should be borne by the project
developer?
DPS: A system impact study is a cost requirement for a project and should
be included in the cost projections for each system type and ultimately
reflected in the rates determined. As discussed above, rates should be
structured to promote development in areas of the transmission
infrastructure that are capable of supporting such development
6. How should the Board determine the return on equity for purposes of setting a
standard rate?
a. What proportion of the cost should be assumed to be equity?
DPS: The Board could examine the financial structure of projects developed
through the clean energy development fund. It is the Department’s understanding
that these were mostly financed through loans or grants. The DPS will examine
data from the Clean Energy Development fund to extract whatever financial data is
available.
7. How should the Board calculate the adjustment factor so that prices are high
enough, but not excessive?
a. Should this adjustment factor incorporate an incentive associated with
production at the most valuable times (i.e., peak) or associated with the
geographic location of the generation unit (i.e., constrained areas)?
DPS: In its earlier comments, the Department discussed the advantages of
an auction. If such a system can fulfill the legal requirements imposed by the
law, it will remove the need to make a determination on the many factors
necessary to define the cost of a renewable system.
In an auction is not feasible, the Department recommends a conservative
approach to setting prices and offers a suggestion for future price setting
exercises. While the Department has not done an in depth analysis, the
range of possible prices and the break even point for potential investors may
vary widely among potential renewable system owners. Even after this
proceeding, we may not truly know what a representative, all-in cost might
be for those systems in question, or more importantly, what constitutes a
sufficient rate to promote renewable development. Since these contracts are
going to be long term in nature, and likely priced above current market price
expectations for alternative supplies (including utility scale renewables),
there is good reason to be cautious, at least initially, in applying any
adjustment factor that raises the rates to be offered.
The Department believes that it may not possible to anticipate the response
to any particular rate offering until it is made. On the one hand, history
shows individuals are installing these systems in response to a net metering
rate which is well below the proposed solar rate, and well below feed-in tariff
rates in other jurisdictions. And while the total installed capacity is small,
there are a significant number of systems. On the other hand, the legislation
contemplates somewhat larger scale systems, which may require improved
financial performance to insure their viability and it also contemplates
increasing the rate of installation. Starting the process with a lower rate and
increasing it if necessary is much easier than attempting to lower a rate that
is too high.
As mentioned above, the Department does not feel that adjustments to costs
should be made to reflect any values imputed by particular performance
characteristics of particular units. This is not to say that rates shouldn’t be
structured to reflect those values, provided the expected revenue equals the
expected costs. For instance, if a wind project were determined to have costs
requiring a rate of 15 cents per kWh, it might be appropriate to structure
that rate so the developer received 12 cents for energy in the summer and 18
cents for energy in the winter when wholesale prices are higher to encourage
availability in the winter. In this way, a project could be provided incentives
which create value for the ratepayer in a way that a properly performing
project should remain indifferent.
8. How should the Board incorporate wheeling charges for power purchased pursuant to a
standard offer contract?
a. Can these charges be minimized or avoided and still be consistent with FERC
requirements?
b. If strategies can be developed to minimize or avoid wheeling charges, will they
be precedential and what are the long-term policy implications?
c. Should system avoided losses be incorporates as well?
d. Do FERC requirements apply in the case of distribution connected generation?
DPS: The Department urges caution when approaching the issue of
wheeling. Since it involves a FERC tariff and could have implications for
other facilities choosing to locate on the Vermont transmission system, the
Department recommends the Board set up a subcommittee to study this issue
in depth.
Implementation Issues
9. Under the statute, the utilities receive RECs associated with SPEED projects.
a. Should the owner be required to apply for RECs and, if so, for resale into what
markets?
b. Should the producers have affirmative obligations to work with the utilities to
assist in the sale and retirement of RECs and other attributes associated with power
purchased under a standard offer contract?
c. Should the attribute be tracked in the NEPOOL GIS?
d. Should the Board create a mechanism to ensure that REC’s are not claimed by
more than one party?
e. How will we ensure that those developing projects are given adequate notice
that participation in the standard offer program limits their ability to make claims
regarding on-site renewable energy use?
DPS: Under the proposed system, a developer does not have an incentive to
apply for and receive RECs for their project. A system where the
Purchasing Agent or SPEED Administrator is inserted between the project
owner and the REC market could present a difficult situation for an
uncooperative owner. For that reason, the Department recommends a strong
condition in the contract requiring any project eligible for RECs to do so and
to include financial penalties within the contract language for failure to do
so.
A similar carve out from the base rate could be made for capacity. This
would create an incentive to provide value to ratepayers. The goal would be
to reflect the actual capacity value received for a plant as determined by its
operating characteristics on the peak hour. A plant owner would be incented
to ensure that their plant was operational during the critical peak periods.
10. Similarly, for capacity, ancillary services and other products including emerging
products, are there any steps that need to be taken to assure that utilities receive any
associated payments or credits?
a. Should the asset be administered in the ISO system or remain outside the ISO
system and be treated as a load reducer?
DPS: A carve out from the base rate could be made to represent the capacity
value of a unit, as is done now with the Rule 4.100 projects and the capacity
adder. This would create an incentive to provide value to ratepayers. The
goal would be to reflect the actual capacity value received for a plant as
determined by its operating characteristics on the peak hour. A plant owner
would be incented to ensure that their plant was operational during the
critical peak periods.
The projects must follow the ISO rules and adopt ISO reporting
requirements. For units with discretion, it should be up to the project owner
whether they want to be an ISO reporting unit or a load reducer.
11. Project Eligibility Issues
a. What steps must a developer take to qualify for the rates in effect at a particular point
in time? Contract? Construction? CPG? Letter of intent? Who will manage the queue?
DPS: Any process developed by the Board to establish a project queue
should have three features:
1. A developer must demonstrate some minimum commitment to a project.
2. Whatever process guarantees a spot in the queue must also lock in the
rates and terms for each project accepted in the queue.
3. A developer must demonstrate the financial capabilities to undertake such
a project. Also, a clear process should be established to qualify utility owned
projects and to determine their effect and the timing of that effect on the
50MW cap and the allocation of power to the individual distribution utilities.
One eligibility aspect the Board should consider eligibility of biodiesel
projects and how they are to be counted. Is a 20 MW generation unit fueled
with B10 biodiesel a 2 kW renewable project? Should the renewable energy
component of the project be 10% of the total output?
b. What process should the Board put in place to allow developers who want to
put projects into service if the interim rates are set in September? Should the Board
develop a separate project queue for such projects? Would this be consistent with the
statute?
DPS: Should the Board find it desirable to establish rates on a faster track
than the September 15 deadline, a survey of existing feed-in tariffs and their
effects could provide an indication to the question of whether the rates
proposed in statute are high enough but not too high. The program could be
initiated with those rates and an appropriate queue structure. It would be
the Department’s position that one criteria for reserving a place in the queue
would be to agree to the rate and terms in effect at the time of the
reservation. Much like a mortgage rate in financing a home purchase, once
the lock in takes place, there is no opportunity to change. Alternatively, the
board could declare that the rates in the original statute are sufficient to start
a program and begin taking applications immediately, Once interim rates
are approved in September, a new queue begins for the rates and terms to be
set in January.
c. How long can a developer hold a rate, or their spot in the queue?
DPS: Developers should be given one year to hold their place in the queue.
However this date could be extended for good cause.
d. Should there be two queue’s, one for rate, and one for interconnection?
e. Should there be formal eligibility requirements for contract award or
participation in the program? If so, what should these eligibility requirements be? Should
they vary by technology?
DPS: Yes, to promote equity, there should be some demonstration of
commitment to reserve a spot in the queue. This can be financial or some
other mechanism.
f. Given the limits on the program size is there need to prevent strategic behavior
(e.g., hoarding of contracts or project queue positions)? If so, how can this be done
without creating excessive barriers to entry? Should some form of security be required or
the proponent be required to demonstrate that they have advanced the development of the
project?
g. How should the Board address the fact that the standard offer must be in place
until 50 MW have been commissioned (not approved)? Does the standard offer need to
contain provisions so that only the first 50 MW qualify for the rates?
DPS: Yes. While the legislation says commissioned, it is the Department’s
opinion that the legislative intent on this point was to create a program that
would have a cap of 50 MW. It is the Department’s position that some form
of security should be required of a project and that an appropriate timetable
be established to assure projects are progressing in a reasonable manner.
Planning activities of the utilities require reasonable expectations of
committed resources.
h. Should the Board reserve a portion of the 50 MW for smaller projects or
projects from particular types of resources? What shares should be so reserved?
i. How should the Board factor in utility projects (that may reduce the 50 MW
maximum)?
i. Should the entire project count towards the owning utility's cap, or should only
their load share (percentage) count toward the cap?
DPS: Utility projects should follow the same queue process as the rest of the
participants in the feed-in tariffs. Their projects should be accounted for in
the same way as any other project.
j. Can existing facilities, such as net metering projects, qualify for the new
SPEED rates? Should refurbished projects or the output from expanded
projects be able to participate?
DPS: No. This program is to develop new renewable resources, not
compensate those who have already installed systems. Incremental additions
to existing systems could be eligible for the feed in tariff, however, provided
an adequate measurement system could be devised to separate production.
k. On a going-forward basis, what is the interrelationship between the Standard
Offer Contract and the SPEED and net-metering programs?
DPS: Each program should continue in its current format, with a developer
choosing which program to sign up.
l. Should the Board set a minimum kW size to qualify?
DPS: Yes. At this point, the Department does not have a recommendation
on size, but 10-20 kW seems like a range below which the net metering
program should cover these systems and feed-in tariff should not apply.
i. Should the Board set qualifications criteria that are inclusive of residential scale
systems?
12. How should future renewable energy technology be considered or addressed?
13. Interconnection. Is it necessary or appropriate to revise the Board's interconnection
rule for smaller (150 kw or less) renewable projects?
a. Should the Board reconsider its net-metering interconnection standards under
Rule 5.100 and the terms and conditions of the interconnection Rule 5.500 to create a
unified interconnection standard for all interconnected electric generation?
DPS: There should be a consistent interconnection standard for generation
projects of the same capacity, regardless of how the output is sold or
metered. This could be accomplished most easily by leaving the net metering
rule (5.100) intact, and by changing Rule 5.500 such that the applicability
section reads as follows:
5.501 Applicability. This Rule applies to all proposed interconnections of
Generation Resources within the State of Vermont which are not (i) lawfully
subject to ISO-NE interconnection rules or successor rules approved by
FERC, or (ii) subject to the Board's net metering rule (Rule 5.100), for which
the interconnection provisions of those rules will govern. All interconnections
of Generation Resources equal to or less than 150 kW of AC capacity that are
not subject to (i) or (ii), above, shall follow the interconnection
procedures specified in Rule 5.100, and are not subject to the procedures
hereinafter. This Rule does not apply to facilities within the State of Vermont
that were interconnected or had obtained all necessary approvals for
interconnection with electric power transmission or distribution systems
prior to 60 business days after the effective date of this Rule.
b. Should interconnection of projects with a capacity of 250 kW and less follow
the net metering rule?
DPS: No, see above. The revised net metering rule directs projects above
150 kW to follow Rule 5.500.
c. Should there be a different interconnection rule for different technologies?
DPS: No. Rules 5.100 and 5.500 accomodate the different technologies.
14. What, if any, standard should the Board adopt for metering and reporting of SPEED
projects eligible for the cost-based pricing under a Standard Offer Contract?
a. Who will be responsible for metering and reporting in connection with standard
offer power allocated by the SPEED Facilitator to utilities?
DPS: Metering should be accurate and secure and provide for remote
monitoring of systems. It should easily feed into a billing system of the
SPEED Agent.
15. The statute specifies that the term of the contract varies from 10 to 25 years. Who
should decide on the duration?
DPS: Excessive contract term choices may make the matrix of rates
unwieldy and difficult to administer. Whatever term is chosen, the Board
should be clear about options available to SPEED project whose feed in tariff
contract has expired. Further, financing and depreciation assumptions
should reflect the physical life of the system. Rates should reflect this value
as well.
16. Do all projects have to apply under Title 30, Section 248 (or 248(j))?
DPS: SPEED projects need to follow the rules as presently in force.
a. Do all projects apply under Board Rule 5.500?
b. Is the Board prepared to handle a large quantity of Section 248 or 248(j)
dockets, and is there potential to delay other Utility 248 requests for infrastructure
upgrades?
c. Is the applicant subject to the standard rate at the time of application or
approval in the event of an unusual delay in granting a Section 248 permit?
17. Should this proceeding address the development of a Section 248 permitting process
for standard offer plants that is similar to what is done for net metered systems? If so,
what is the appropriate avenue for developing such a review process?
18. If farm methane projects are allowed to retain ownership of the RECs:
a. Will this require a separate standard contract for farm methane projects?
DPS: Yes. It is likely that different project types will have different, but
standardized, contracts anyway.
b. Should the value of the RECs be included in determining an appropriate rate
for methane projects?
DPS: The rate should be determined including the fact that some revenue
can be expected from the sale of RECs.
19. The eligibility date for standard offer contracts for non-utility-owned plants is
not clearly listed in the statute, thus the PSB may need to make a determination on the
eligibility date for non-utility plants as soon as possible.
a. What date should be selected?
b. What criteria should the Board employ in determining an eligibility date?
c. How should this Board establish, as quickly as possible, parameters that will
enable project development to continue without a construction season hiatus while we
work out the standard offer program process?
DPS: Whatever date is selected by the Board, once a project reserves a place
in the queue, rates and terms are not subject to change to reflect program
updates. In order to have a minimal effect on the summer construction
season, the Board should set interim rates as soon as possible. One possible
solution would be to adopt the rates in statute.
20. The law establishes a 2.2 MW size limit on projects.
a. Does this prohibit expanding a project if it is eligible for feed-in rates?
b. Could a developer, at a later date, add additional solar panels or wind turbines
to an existing SPEED project?
DPS: Yes. A developer should be able to expand a project to qualify up to
the 3.3 MW limit. Any system which expands its capacity and is paid under
separate tariffs, must have a mechanism to separate the system production.
21. What process should the Board use, and what standards should the Board rely on, to
determine where “equity requires” that a retail electricity provider be relieved, in whole
or in part from standard offer purchases, if it makes a showing that it receives at least
25% of its energy from qualifying SPEED resources?
22. Would an auction mechanism be a useful means for determining the rates necessary
to meet the statutory directive that requires a price “sufficient . . . for the rapid
development and commissioning of plans and does not exceed the amount needed to
provide such an incentive”?
DPS: Yes. An auction process will allow producers to specify what they
need to develop their projects. It is frequently used in power procurement
activities.
SPEED Contract/Facilitator Issues
23. SPEED Facilitator. Board rules limit the SPEED Facilitator’s ability to enter into
contracts. Do these need to be amended? Or has the statute obviated the need to
change the rule? Can the matter be resolved through an order issued in this
investigation?
24. SPEED Facilitator standard contract. What should a standard contract contain?
a. Can we use the VEPPI contracts as a model?
b. What reporting requirements should be included?
25. How should the costs of the SPEED Facilitator be apportioned between developers
and utilities?
a. Should the allocation be 50/50 as in the small power arrangements?
b. How would this allocation occur for small projects?
26. What skills/expertise should the SPEED facilitator have? For example, should the
SPEED facilitator have deep knowledge of the NEPOOL GIS system for tracking
attributes of a project?
27. Will all Standard Offer generation projects be treated the same way as far as paying
costs for metering, transformers, losses, data collection, etc. or will ther be different
rules for smaller generators, and if so where will the cutoff be?
28. What contract provisions are needed to protect ratepayers? What contract
provisions should be avoided to limit undue barriers to these projects?
DPS: The requirement to obtain RECs should be clearly spelled out in the
contract.
Utility Settlement and Billing
29. How will extremely small SPEED projects be allocated to utilities? (This is especially
important in the context of small resources – i.e., 10kW – where a pro rata allocation
could result in some utilities being allocated less than 1 kW on an hourly basis.)
DPS: The Department feels there should be a size restriction on projects
eligible for this rate due to the significant transaction costs involved with
these small projects and the availability of the net metering program, which
has proven successful in encouraging smaller projects. However, if small
projects are allowed and the allocation does not work for ISO settlement
purposes, a system where the entire output of small resources is absorbed by
the host utility could be used. The host utility would receive a credit on their
allocation of either the calculated or actual performance of each unit which it
hosted in its entirety. This credit would be adjusted to reflect the amount
that utility would have purchased from the unit under a group allocation for
each technology.
30. Are there any barriers to implementation inherent in the ISO New England settlement
process used by utilities to settle generation contracts and, if so, how can they be
overcome?
31. How will the utility allocations be treated in the context of settlement with ISO New
England?
32. How will REC’s be allocated, especially in the context of utility allocations of less
than 1 kW?
33. Will a minimum generator size be required to facilitate utility settlement?
34. How will the utility generator provisions of the legislation be implemented?
a. If CVPS and GMP build large numbers of utility owned generators, standard
offer charges could be shifted to the remaining municipal and cooperative customers,
skewing overall rate impacts. Should there be limits on utility offsets?
DPS: No. Since rates are supposed to represent costs, the impact may not be
large.
b.Credits received for projects developed by retail electricity providers appear to
allow for a proportional reduction in obligations to receive power under the feed-in tariff
program. In addition to reviewing the effects of development by retail providers on the 50
MW ceiling, how will the Board implement the adjustment for the retail electricity
providers?
Other Cost and Pricing Issues
35. How should factors like outage rates, availability, capacity factor, and generic
performance criteria be used in developing the appropriate rate?
DPS: The estimated production values of these plants are critical to
establishing an appropriate rate. As stated previously, the department feels
that rates should be based on a well performing, adequately maintained
installation that is in a proper location. To do otherwise could create rates
which could encourage inefficient plant design and operation.
36. How should the end of life value be considered in the cost calculation for the various
technologies?
a. Should the projects become the property of the ratepayers upon the expiration
of the contract?
DPS: Rates established should consider the end of life value in establishing a
rate. There would seem to be several methods to do this. One would be to
make the units become the property of the utility upon expiration of their
contract. Alternatively, an end of contract salvage value could be estimated
which would be included as a negative cost in computing rates.
37. Should the rate structures differentiate components of each project, such as energy,
capacity, and RECs.?
DPS: Yes. A structure that provides payment for the attributes and other
performance characteristics will provide incentive to a developer to operate
their facility in a way that produces the most value for Vermont ratepayers.
38. Should rates be designed to include peak and off peak components as well as
incentives to produce at the most useful times?
DPS: Yes. Although the Department recognizes there may be a limit on the
size and complexity of the rate matrix.
39. Should rates include a geographic component to promote generation in constrained
areas?
DPS: Since rates equal costs, such an incentive will not promote
development of a project, only its location. There would seem to be a risk
that there could be significant free ridership if rates were increased to reflect
location. If the Board decides to include such an adder, it should only be for
projects where there is some discretion as to location.
40. Should property tax implications for the installation of renewable systems and income
tax implications from the sale of output from the facilities be addressed in developing
costs?
41. Should the rate reflect any needed system improvements resulting from the
installation of a renewable system on the grid?
DPS: No. Rates should reflect an installation that is located in an
appropriate spot on the grid and provide such an incentive.
42. How should the contract price reflect: (1) the fact that a portion of project costs will
escalate over time? (2) there may be economies of scale related to larger capacity
projects?
DPS: For a project with potentially escalating costs, a portion of the rate can
be escalated on an annual basis to account for increasing costs. The
Department would not support a levelized rate, but would prefer a rate (or
portion of a rate) that escalated based on actual performance of a particular
component of costs, based upon some agreed upon index. Economies of scale
associated with larger capacity projects should be dealt with in the
granularity of rates.
43. Should the Board establish a Vermont-manufactured multiplier to promote the
installation and use of technology manufactured in the state? If so, what level of support
would be appropriate?
DPS: No. Ratepayers should not be paying for economic development
programs. The Department would not object if some other economic
development entity wanted to assume responsibility for that portion of the
rate.
44. How should the Board address public (non-taxable) entities versus private (taxable)
entities in determining generic costs?
DPS: This should be addressed in the granularity of the rates. If there are
significant differences in the costs faced by different business types, that
should be reflected, within reason, in the rates.
45. Wind energy has different generic costs at different mean average wind speeds; how
should the Board decide the appropriate state mean wind speed used to determine costs?
DPS: The board should determine all rates based on a project that is
favorably sited.
46. How should issues related to capital structure and financing be addressed in
developing pricing information?