EEA Database on Distributed Generation

WHAT'S NEW:

No recent state activity has been identified.

Permits by rule are typically issued instead of exemptions (a list of exemptions for permits by rule area listed here).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, VOC, or PM10, or 250 tons per year of NOx, 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 is a permit by rule for IC engines and turbines. Gas or liquid fuel-fired stationary internal combustion engines or gas turbines that are rated at less than 500 hp are exempt from permitting by rule. 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.

A list of de minimis exemptions can be found here.

MINOR SOURCE PERMITTING

EGU Standard Permit

Electric generating units 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 permit option applies to electric generating units that are new or modified after May 16, 2007.

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 Highway 37 to include Bosque, Coryell, Hood, Parker, Somervell and Wise Counties. The standards are as follows:

NOx Emission Standards for Units up to 10 MW

	Installed Prior to 2005	Installed in 2005 or Later
East Texas
Operates +300 hrs/yr	0.47 lb/MWh	0.14 lb/MWh (with a capacity greater than 250 kW)
Operates less than 300 hrs/yr	1.65 lb/MWh	0.47 lb/MWh
Any unit with a capacity of 250 kW or less	0.47 lb/MWh	0.47 lb/MWh
West Texas
Operates +300 hrs/yr	3.11 lb/MWh	3.11 lb/MWh
Operates less than 300 hrs/yr	21 lb/MWh	21 lb/MWh

All units (east and west) >10 MW operating more than 300 hrs must meet a rate of 0.14 lbs NOx/MWh and those operating less than 300 hrs must achieve a rate of 0.38 lb NOx/MWh.

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. The following fuel sulfur limits appy -

1. Gaseous fuels used must have no more than 10 grains of sulfur per 100 cubic feet.

2. Landfill gas, digester gas, stranded oilfield gas, or gaseous renewable fuel containing no more than 30 grains total sulfur per 100 dry standard cubic feet; or

3. Liquid fuels (including renewable fuel) not containing waste oils or solvents and containing less than 0.05 percent by weight sulfur.

Fees: $100 for units <1 MW
The fee will be waived for units < 1 MW at a site that have certified NOx emissions that are less than 10% of the standards required by this EGU standard permit.

EGUs firing any gaseous or liquid fuel that is at least 75% landfill gas, digester gas, stranded oil field gas, or renewable fuel content by volume, shall meet a NOx emissions limit of 1.90 lb/MWh (with the exception of EGUs in West Texas, which must follow the NOx limits listed in the table above).

Turbine and Engine Permit by Rule

Gas or liquid fuel-fired stationary internal combustion reciprocating engines or gas turbines that operate in compliance with certain NOx limits based on fuel-type, year of operation, size and other criteria. The NOx limits range from 2.0 g/hp-hr to 11.0 g/hp-hr for engines rated 500 hp or greater. For gas turbines rated at 500 hp or greater, NOx limits of 3.0 g/hp-hr typically apply.

A list of all permits by rule can be found here.

Other Permitting Requirements

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-Galveston-Brazoria 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 Highly Reactive Volatile Organic Compounds (HRVOC). The HRVOC cap and trade program began on January 1, 2007, whereas the NOx reduction program began on January 1, 2002 and the final reduction in the emissions cap occurred in 2007.

MAJOR NSR/PSD PERMITTING

A potential to emit 250 tons of any criteria pollutant in attainment areas triggers PSD. 100 tons of NOx, VOCs, PM or CO triggers NSR in moderate nonattainment areas.

TREATMENT OF EMERGENCY ENGINES

Gas or liquid-fired stationary internal combustion engines and gas turbines rated at 500 hp or greater are permitted by rule (see details above for permitting by rule).

SITING REQUIREMENTS FOR NON-UTILITY GENERATORS:

Texas Rules for Siting

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.

BUILDING, ZONING AND FIRE CODES:

Building Codes: Texas does not adopt or enforce codes on a statewide level. Localities that choose to adopt codes must adopt a version of the IBC.

Energy Codes : Texas enforces a minimum building energy code for new commercial construction. It is based on the 2000 IECC with 2001 ICC amendments. State-funded buildings must meet ASHRAE 90.1-2004. [1]

Energy Conservation Office

Fire Codes: Texas does not adopt or enforce codes on a statewide level. When local code does not cover a building, the NFPA Life Safety Code is enforced.

State Fire Marshal

Zoning: Zoning and planning happens at the local level. Check with each jurisdiction regarding their zoning codes.

Resources (information may not be as current as provided above)

A general overview of each state’s enacted codes can be found HERE.

The International Code Council Adoption page gives state-by-state adoption status of specific ICC codes, as well as information about code adoption by some municipal governments within that state.

Information about energy codes can be found at the DOE’s Building Codes for Energy Efficiency page or at the Building Codes Assistance Project.

INTERCONNECTION REQUIREMENTS:

Ongoing activity/ policy updates:

HB 3693 became effective in September 2007. The bill requires major changes to Texas net metering and interconnection policies. Public Utilities Commission of Texas (PUCT) documents on this subject are under Docket 34890 and the Electric Reliability Council of Texas (ERCOT) is looking at the issue through its Distributed Generation Task Force. In June 2008, the PUCT issued proposed interconnection rules, which would amend §25.242 and publish new §25.217. The proposed new §25.217 addresses interconnection, and the amended §25.242 would establish metering requirements for DG. Comments were due by July 21, 2008, a public meeting was held on August 5th, and the order for adoption is tentatively set for consideration in the October 23, 2008 Open Meeting. The draft rule proposes allowing for the interconnection of systems up to 2 MW.

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.

Utility	Contact Info
TXU Energy Delivery	Ken Brunkenhoefer Distributed Generation Consultant TXU Electric Delivery Lincoln Plaza 500 N. Akard, Rm. 12-205 Dallas, Texas 75201 Phone: 214.486.5547 Fax: 214.486.217 E-mail: brunkenhoefer@txued.com
Texas Central Power and Light (AEP)	Distributed Generation Coordinator 1 Riverside Plaza Columbus, Ohio 43215 Phone: 614-716-1377 E-mail: dgcoordinator@aep.com
Entergy Texas	John H. Biehn Phone: 409-785-2204

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.

EXIT FEES:

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.

UTILITY STANDBY RATES:

Texas does not have a statewide policy on standby rates. Policies for individual utilities are summarized below.

TXU Energy: There is no standard standby rate. Customers seeking standby service would need to contract with the utility to be charged under a regular tariff. Typical rates are based on both demand and energy charges. There may be a demand ratchet depending on the contract with the utility.

Reliant Energy Retail Services: There is no standard standby rate. Customers seeking standby service would need to contract with the utility to be charged under a regular tariff. Typical rates are based on both demand and energy charges. There would be no demand ratchet.

Texas

WHAT'S NEW:

AIR EMISSIONS REGULATIONS:

BUILDING, ZONING AND FIRE CODES:

EXIT FEES: