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Contact Information:
Texas Commission on Environmental Quality
P.O. Box 13087
Austin, TX 78711-3087
(512) 239-1250
Or view the Department's
Website
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TEXAS
The Texas Division of Environmental Quality is currently discussing whether
to roll-back the implementation of their 2005 limit of 0.14 lb NOx/MWh for
small electric generators in East Texas and make other changes to the rule.
A revised draft under consideration exempts generators smaller than 100
kW. A meeting on this topic will be held on April 22. More information can be found on the Latest News Page.
DE MINIMIS EXEMPTIONS:
Permits by rule are issued instead of exemptions. Each permit by rule has a specific set of requirements that
a unit must meet. There are over 100 types of permit by rule, however no unit can qualify for a permit by rule
if it exceeds 25 tons per year of SO2 and PM or 250 tons per year of NOx, VOCs and CO. If the unit meets all requirements
in a permit by rule it registers with the state, but it does not receive a permit. In the registration process
sources must show that they will meet all applicable requirements of the permit by rule. The permit by rule that
applies to small boilers applies to units up to 40 MMBtu/hr. If the unit is greater than 10 MMBtu/hr it must meet
a 0.1 lb/MMBtu NOx emission rate. There was a permit by rule for IC engines and turbines, but it is being phased
out so these units will all be permitted by the Standard Permit discussed below. The state also has specific limits
(such as fuel sulfur and opacity) for each criteria pollutant that automatically apply to all unit's in the state
(regardless of permitting requirements). These limits are so high that they are not an issue for modern technologies.
MINOR SOURCE PERMITTING:
Minor source turbines and internal combustion engines are eligible for a standard permit. The Texas standard permit
is roughly equivalent to what is normally called a "general permit" in other states. The new permit option
applies to electric generating units that are new or modified after June of 2001. However, only small stationary
internal combustion engines or turbines are likely to be eligible. Emergency units may opt to register under this
program, but are covered separately under a permit by rule.
The requirements for East Texas are much more stringent then those of West Texas due to the local ozone nonattainment
problems. East Texas includes all counties east of Highway 35 or 37 to include Bosque, Coryell, Hood, Parker, Somervell
and Wise Counties. The standards are as follows:
NOx Emission Standards for Units <10 MW
| |
Installed Prior to 2005 |
Installed In 2005 or Later***See Latest News above |
| EAST TEXAS |
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| Operates 300+ hrs/yr |
0.47 lb/MWh
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0.14 lb/MWh
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| Operates less than 300 hrs/yr |
1.65 lb/MWh
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0.47 lb/MWh
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| WEST TEXAS |
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| Operates 300+ hrs/yr |
3.11 lb/MWh
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3.11 lb/MWh
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| Operates less than 300 hrs/yr |
21 lb/MWh
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21 lb/MWh
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All units (east and west) >10 MW operating more than 300 hrs must meet a rate of 0.14 lbs/MWh and those operating
less than 300 hrs must achieve a rate of 0.38 lb/MWh. The 2004 standard for East Texas represents BACT-plus and
is expected to allow fuel cells, micro turbines and some clean turbines using catalytic combustors or flue gas
cleanup. The 2005 standard is going to be reevaluated upon completion of a market feasibility study due out by
the end of this year. There is no public comment period required under the standard permit and issuing a permit
generally takes between 30-45 days.
Special Considerations
Units using combined heat and power (CHP) are eligible for credit from the heat recovered at a rate of 1 MWh
for each 3.4 MMBtu of heat recovered. The heat recovered must also be a minimum of 20% of total energy output by
the unit.
Gaseous fuels used must have no more than 10 grains of sulfur per 100 cubic feet.
Fees: $100 for units <1 MW
$0 for units with emission <10% of permit standards and < 1MW
$450 for units >1 MW
East Texas units burning landfill gas, digester gas or oil field gas with <1.5 grains hydrogen sulfide or 30
grains sulfur compounds shall meet a NOx emission rate of 1.77 lb/MWh.
Most new units opt for the standard permit, however the state does have a program for issuing a construction
permit as part of state new source review. Units being permitted through this method are required to do BACT for
all criteria pollutants, but for most pollutants that just means complete combustion. There is no established cost
threshold for BACT, however state officials suggested that $10,000 per ton for controlling NOx would be too expensive.
The processing time for this type of permit can range from 4-12 months. There is a 30 day public comment period
as well.
All units in the Houston area must also participate in the cap and trade program if the source has an uncontrolled
potential to emit greater than 10 tons per year of NOx or VOC. This is a NOx allowance and cap and trade program
similar to the Title IV SO2 program or OTR NOx Budget. It applies to all stationary sources with the potential
to emit 10 tons of NOx or more per year. Controlling emissions to less than 10 tons per year does not exempt a
unit from participating in this program. Compliance reporting is due each year on March 31 showing that the sources
had allowances in hand for the preceding year. The penalty for not having enough allowances to cover emissions
at the end of the year is a 110% deduction from the next year.
Allowances are allocated to sources initially based on historical activity levels times the higher of their
historical levels or the new emission limits in section 117. This is ramped down from 2002 through 2004 by one
third each year until sources are allocated at their section 117 levels starting in 2005. Sources that apply for
permits after 1/2/01 will never receive allocations and must purchase all of their allowances. The first round
of allocations are due 1/1/02. Allowances can be traded and banked.
Allowances can be converted into ERCs if they are permanent reductions and meet the other criteria but they
cannot be used for netting purposes. Allowances are defined as whole tons only.
MAJOR NSR/PSD PERMITTING:
A potential to emit 250 tons of any criteria pollutant in attainment areas triggers PSD. 25 tons of NOx or VOCs
in severe areas and 50 tons in serious areas triggers NSR. 100 tons of NOx, VOCs, PM or CO triggers NSR in moderate
nonattainment areas.
TREATMENT OF EMERGENCY ENGINES:
Internal combustion engines and gas turbines used for emergency and/or standby services are permitted by rule
(see details above for permitting by rule), however annual operating hours are limited to 10% of the normal annual
operating schedule of the primary equipment. Emergency engines may also qualify for the standard permit for engines
and turbines discussed above.
All self-generating energy facilities must register with the Public Utility Commission of Texas.
Sec. 39.351. REGISTRATION OF POWER GENERATION COMPANIES.
(a) A person may not generate electricity unless the person is registered with the commission as a power generation company in accordance with this section. A person may register as a power generation company by filing the following information with the commission:
(1) a description of the location of any facility used to generate electricity;
(2) a description of the type of services provided;
(3) a copy of any information filed with the Federal Energy Regulatory Commission in connection with registration with that commission; and
(4) any other information required by commission rule, provided that in requiring that information the commission shall protect the competitive process in a manner that ensures the confidentiality of competitively sensitive information.
(b) A power generation company shall comply with the reliability standards adopted by an independent organization certified by the commission to ensure the reliability of the regional electrical network for a power region in which the power generation company is generating or selling electricity.
(c) A power generation company may register any time after September 1, 2000
Texas Rules for Siting
There are no exit fees for DG applications smaller than 10MW. Although the Restructuring Act allows for stranded
cost recovery for applications greater than 10 MW, the PUCT made the determination in June 2003 that utilities have recovered
their stranded costs. This assessment will be reevaluated in January 2004. (See below)
A utility has a right to recover net, non-mitigable stranded costs incurred in purchasing power and providing
electric generation service (§39.252). Stranded costs are determined by the Commission's excess costs over
market model and can be recovered beginning January 1, 2002 through a Competition Transition Charge (§39.157),
After January 10, 2004 the Commission shall establish a true-up procedure to finalize stranded costs and to
ensure that utilities do not over-recover stranded costs (§39.252).
In terms of DG, a utility can assess a Competitive Transition Charge upon a customer who installs on-site
generation greater than 10MW after 12/31/99. This charge is the product of the on-site generation times the
competitive transition charge. See rules below from
Senate Bill 7 (06/18/99):
Sec. 39.252. RIGHT TO RECOVER STRANDED COSTS.
(a) An electric utility is allowed to recover all of its net, verifiable, nonmitigable stranded costs incurred
in purchasing power and providing electric generation service.
(b)(1) Recovery of retail stranded costs by an electric utility shall be from all existing or future retail
customers including the facilities, premises, and loads of those retail customers, within the utility's geographical
certificated service area as it existed on May 1, 1999. A retail customer may not avoid stranded cost recovery
charges by switching to new on-site generation except as provided by Section 39.262(k). For purposes of this
subchapter, "new on-site generation" means electric generation capacity greater than 10 megawatts capable of
being lawfully delivered to the site without use of utility distribution or transmission facilities and which
was not, on or before December 31, 1999, either
(A) a fully operational facility; or
(B) a project supported by substantially complete filings for all necessary site-specific environmental
permits under the rules of the Texas Natural Resource Conservation Commission in effect at the time of filing.
(2) If a customer commences taking energy from new on-site generation which materially reduces the customer's
use of energy delivered through the utility's facilities, the customer shall pay an amount each month computed
by multiplying the output of the on-site generation by the new sum of competition transition charges under
Section 39.201 and transition charges under Subchapter G which are in effect during that month. Payment shall be
made to the utility, its successors, an assignee, or other collection agent responsible for collecting the
competition transition charges and transition charges and shall be collected in addition to the competition
transition charges and transition charges applicable to energy actually delivered to the customer through the
utility's facilities.
Sec. 39.262. TRUE-UP PROCEEDING.
(k) Notwithstanding Section 39.252, to the extent that a customer's actual load has been lawfully served by a
fully operational qualifying facility before September 1, 2001, or by an on-site power production facility with
a rated capacity of 10 megawatts or less, any charge for recovery of stranded costs under this section or
Subchapter G assessed on that customer after the facility becomes fully operational shall be included only in
those tariffs or charges associated with the services actually provided by the transmission and distribution
utility, if any, to the customer after the facility became fully operational and may not include any costs
associated with the service provided to the customer by the electric utility or its affiliated transmission and
distribution utility under their tariffs before the operation of that qualifying facility. To qualify under this
subsection, a qualifying facility must have made substantially complete filings on or before December 31, 1999,
for all necessary site-specific environmental permits under the rules of the Texas Natural Resource Conservation
Commission in effect at the time of filing.
COMPETITIVE TRANSITION CHARGES
The PUCT has determined that no utility is estimated to have stranded costs, so no CTC's have been set. This may change after the final market evaluation.
CTC Ruling (page 40)
International Code Council State Adoption Information Page
Provides an easy to use US map to locate state and local adoption of the International Code Council's model codes.
US DOE's Office of Building Technology, State and Community Programs, Building Codes Database
The US DOE's database provides a comprehensive look at a state's building code implementation and enforcement
process.
The PUCT has created state regulations concerning distributed generation that can be accessed through
their web site. In particular two substantive rules apply to DG. They are:
- Substantive Rule §25.211 Interconnection of On-Site Distributed Generation (DG),
- Substantive Rule §25.212 Technical Requirements for Interconnection Of On-site Distributed Generation (DG).
The interconnection process consists of the following steps:
1) Filing of an application by the DG Applicant with the Transmission and Distribution Utility (TDU)
2) TDU Review of the application
3) Responses specifying the requirements for further study, if needed, and the technical requirements to interconnect
4) Approval of an agreement between the DG applicant and the TDU
5) Connection, testing and operation of the DG project
The interconnection process has been designed to specify the appropriate level of review and the associated
technical and equipment requirements for each DG project. The intent is for small, low-impact DG projects to
be reviewed quickly, the technical and equipment requirements to be only as complex and expensive as required
for safe operation, and fees paid by the customer to be fair and justified. The larger the project and the more
complex the interconnection scheme, the higher the costs, both for studying the interconnection scheme and for
the necessary electrical equipment to interconnect.
For example, consider the simplest case, with the following attributes: A customer wishes to connect a
pre-certified DG system smaller than 500 kW. A pre-certified system is a known collection of components
that has been tested and certified either by the TDU or by a qualified third party (see PUCT rules
§25.211(c)(12),
§25.211(k)). The line to which interconnection is desired is a radial feeder
circuit, i.e., there is only one path from the interconnect point to the TDU's distribution substation
(this is the most common situation). The DG will export either no power to the TDU system at all, or
less than 15% of the total load on the feeder. Also, it will add no more than 25% of the short-circuit
current on the feeder, as determined by the TDU's review of the application.
In this example, no further interconnection study is required and the TDU may not charge for one, and the
equipment requirements are minimal and pre-specified for this case
(PUCT Rule §25.212(d, e)).
The TDU
is required to interconnect the DG within four weeks of receipt of customer's application.
In all other cases, a TDU may need to conduct an interconnection study, and may charge the customer
for the costs of the study. For example, a DG system that is not pre-certified must be evaluated to
ensure that the system will operate safely on the TDU's system. Larger DG systems can have
significant impacts on the TDU system, and this is the reason that a comparison of the DG size to
the load on the existing system is important. An estimate of the study costs must be provided to
the customer before the TDU performs the study. The study must be completed by the TDU in four weeks
for a radial connection, and six weeks for a network connection. Written results must be presented
to the customer, detailing the findings and including an estimate of capital upgrades required, if any.
These capital upgrades are the responsibility of the customer, who must enter into a contract with the TDU
to implement them.
Connecting to a networked feeder system (one in which there are multiple paths from the interconnect point
to the distribution substation) poses more difficult questions of equipment and system protection, requiring
more detailed technical analysis. The study may take no longer than six weeks, and a written report of TDU's
findings must be supplied to the customer. Moreover, the TDU must take into account the benefits
realized from the DG project in addition to the costs incurred by it (
see PUCT Rule §25.211(g)(1)(C)).
In the case of a proposed network connection, additional guidelines apply. Inverter-based DG systems,
and all DG systems that do not export power to the grid, will be approved without further study, unless
the total distributed generation on the feeder, including the new facility, is more than 25% of total
load on the network. Total load is defined as the sum of all customer loads on the feeder. If the
new DG application would push total DG on the feeder over this 25% load limit, then the proposed DG
facility will be subject to interconnection studies that must be completed within six weeks.
A TDU can reject a DG project on a networked system if it can demonstrate valid technical or
safety reasons for denying the interconnection, but the TDU must make good-faith efforts to
resolve the issue with the customer. TDUs must make reasonable efforts to accommodate DG projects
that propose to export power on a networked system. Such reasonable efforts should include
alternate methods of interconnection such as converting to radial service, if practical.
Entergy Texas Distribution Interconnection Agreement
Texas Central Power and Light (AEP) Interconnection Information
The first step in DG interconnection planning is to contact one's transmission and distribution utility to discuss the process.
Contact information is summarized in the table below.
The tables below detail each utility's fee for pre-interconnection studies of DG.
Non-Exporting Distributed Generation Units
| |
Non-Exporting |
0 to 10 kW |
10+ to 500 kW |
500+ to 2000 kW |
2000+ to 10,000 kW |
| Entergy Texas |
Pre-certified, not on a network |
NA |
NA |
$225 |
$225 |
| Not pre-certified, not on a network |
$225 |
$225 |
$225 |
$225 |
| Pre-certified, on network |
NA |
NA |
$225 |
$225 |
| Not pre-certified, on network |
$225 |
$225 |
$225 |
$225 |
| Texas Central Power and Light (AEP) |
Pre-certified, not on a network |
$0 |
$200 |
$400 |
$600 |
| Not pre-certified, not on a network |
$100 |
$300 |
$540 |
$704 |
| Pre-certified, on network |
$100 |
$400 |
$1,000 |
$2,000 |
| Not pre-certified, on network |
$380 |
$865 |
$1,535 |
$2,432 |
| TXU Energy Delivery |
Pre-certified, not on a network |
$0 |
$180 |
$510 |
$860 |
| Not pre-certified, not on a network |
$220 |
$320 |
$650 |
$1,000 |
| Pre-certified, on network |
$200 |
$960 |
$2,550 |
$3,000 |
| Not pre-certified, on network |
$330 |
$1,725 |
$2,550 |
$3,653 |
Exporting Distributed Generation Units
| |
Exporting |
0 to 10 kW |
10+ to 500 kW |
500+ to 2000 kW |
2000+ to 10,000 kW |
| Entergy Texas |
Pre-certified, not on a network |
$225 |
$300 |
$1403 |
$2205 |
| Not pre-certified, not on a network |
$225 |
$500 |
$1976 |
$2644 |
| Pre-certified, on network |
$500 |
$1300 |
$2900 |
$3705 |
| Not pre-certified, on network |
$500 |
$1850 |
$3440 |
$5000 |
| Texas Central Power and Light (AEP) |
Pre-certified, not on a network |
$75 |
$300 |
$1,000 |
$75 |
| Not pre-certified, not on a network |
$150 |
$635 |
$1,205 |
$2,000 |
| Pre-certified, on network |
$160 |
$767 |
$2,377 |
$2,182 |
| Not pre-certified, on network |
$495 |
$1,246 |
$2,856 |
$2,878 |
| TXU Energy Delivery |
Pre-certified, not on a network |
$0 |
$180 |
$510 |
$3,357 |
| Not pre-certified, not on a network |
$220 |
$320 |
$650 |
$1,000 |
| Pre-certified, on network |
$200 |
$1,290 |
$3,300 |
$3,650 |
| Not pre-certified, on network |
$330 |
$1,890 |
$3,440 |
$3,780 |
* Fee Applicability
- No fee is charged for any pre-certified (according to PUCT definition) DG unit up to 500 kW that exports not more than 15% of the total load on a single radial feeder and contributes not more than 25% of the maximum potential short-circuit current on a single radial feeder
- No fee is charged for any pre-certified (according to PUCT definition) distributed inverter based generation unit up to 20 kW connected to a distribution network.
- For any pre-certified DG unit up to 500 kW that exceeds the limits defined in (1) above, or any pre-certified DG unit above 500 kW, the above fees apply as required for any pre-interconnection studies required by the Company.
- For any non-certified DG unit, the above fees apply as required for any pre-interconnection studies required by the Company.
- The above fees apply for any pre-interconnection studies required by the Company for interconnection of DG to either radial feeders or distribution networks.
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