Monthly Archives: September 2014

North Carolina and EPA’s Proposed Carbon Rule

September 30, 2014. On June 2, the U.S. Environmental Protection Agency  released  a draft rule to reduce  carbon dioxide (CO2)  emissions from power plants.  Gov. Pat McCrory’s administration has taken a number of opportunities  to  question the legal basis for the  rule. An earlier post described  a presentation by DENR Deputy Secretary Don van der Vaart  to the N.C.  Energy Policy Council soon after EPA  released the draft rule in June.  DENR actually began staking out a position in opposition to the proposed carbon rule even earlier. (See the DENR website for a number of agency policy documents related to the carbon rule.)  Each time, DENR focused on legal arguments — challenging EPA’s authority to regulate a power plant’s CO2  emissions under Section 111 of the Clean Air Act —  rather than the actual impact of the rule on the state and its electric utilities.

Evaluating the impact of the rule on an  individual state can  be challenging because the rule takes an innovative approach to reducing CO2. Instead of putting the burden and cost of CO2 reductions entirely on the power plants,  the rule tries to harness  other  trends in energy generation — increased  reliance on renewable energy;  adoption of  energy efficiency standards for buildings, appliances and equipment; and a shift in generation from coal-fired plants to natural gas units — to help lower CO2 emissions associated with power generation.  Many of those trends developed in response to other environmental concerns (stricter  air quality  standards for ozone and particulates) or economic incentives (the lower cost of natural gas). EPA’s proposed  carbon rule builds on those trends to also drive down CO2 emissions associated with power generation.

Steps  North Carolina has taken over the last 10-15 years to increase renewable energy  generation and energy efficiency seem to put  the state  in a favorable position to meet the CO2 reduction goal in the rule and come out the other side with competitive energy costs.  This post is intended to provide some  (very basic) background on how the rule works and to  identify the questions that need to be answered to understand what more the state may need to do to meet the CO2 reduction goal in the proposed rule.


♦ The rule only addresses CO2 emissions associated with electric generating units (EGUs) that burn fossil fuels; the rule does not affect industrial sources of CO2.

♦ The rule sets a carbon reduction goal for each state in the form of a rate – pounds of carbon dioxide emitted per megawatt hour of electricity generated or CO2/MWh.

♦ Instead of setting a CO2 emission limit for each EGU, EPA proposed a statewide average CO2 emission rate – allowing the goal to be met in part by shifting electric generation from high to low emission units; increasing renewable energy and nuclear generation; and creating “savings” through energy efficiency measures.

♦ The rate is based on net generation (electricity delivered to the grid) rather than gross generation measured at the EGU. Net generation excludes energy used at the power plant to run fans, pumps, motors and pollution control devices.

♦ The rule sets a final goal for each state to meet in 2030 and interim goals for 2020-2029.

♦  CO2 reduction goals differ from state to state. In calculating the goals, EPA considered the existing mix of electric generation facilities in each state (nuclear, coal, natural gas) and each state’s potential for  increased renewable energy generation and growth in energy efficiency savings.


State goals are not based on simply requiring  fossil-fuel burning power plants to reduce their CO2 emissions per megawatt hour from 2012 levels.  Although  EPA used the EGU’s 2012 reported emissions of CO2 as one factor in calculating  the goals, it is not quite correct to describe 2012 as the “base year” for reductions.   The state goals represent something different — reductions in EGU emissions combined with a shift in electric generation capacity to cleaner sources (such as renewable energy and nuclear power) and increases in energy efficiency. More about the rate calculation below.

To set the state CO2 emission rate goals, the EPA rule adjusted the  2012 calculation of CO2/MWh in two ways:

1. EPA reduced the net CO2 emissions  reported by regulated EGUs in 2012 (the numerator in the CO2/MWh equation) by assuming those units can achieve a 6% improvement in heat efficiency. In states where there are both coal-fired plants and natural gas plants, EPA adjusted the numerator again if any natural gas plant in the state operated at less than 70% utilization. Assuming  every natural gas plant could operate at 70% utilization, EPA shifted a corresponding amount of electricity generation from  coal-fired plants to the underused natural gas plants and and adjusted the pounds of CO2 emitted to reflect the natural gas plants’ lower CO2 emissions rate.

So the numerator in the goal represents pounds of CO2 emitted by  the state’s existing power plants after each individual plant has become more heat efficient and after power generation across the entire system has been  reallocated  to better utilize low-emission natural gas units. Both adjustments reduce the amount of CO2 generated by the EGUs  below the amount actually reported  in 2012.

2. EPA then adjusts the denominator in the CO2/MWh equation to spread the pounds of CO2 generated  by the EGUs across the megawatt hours generated by all electric generating sources in the state and megawatt hours of electric generation saved through energy efficiency measures. The denominator becomes:  total megawatt hours generated by the EGUs + new renewable energy generating capacity + new or preserved nuclear generation capacity + an estimate of annual avoided power generation associated with demand-side energy efficiency.  (“Preserved” nuclear power refers to  an existing nuclear plant operating beyond a previously announced closure date.)

The final 2030 CO2 emissions goal as a rate =

Net CO2 emissions for regulated EGUs – 6% heat efficiency*
Total net MWh (EGUs + renewable energy + new/preserved nuclear + avoided generation)

* In some cases there has also been an adjustment for under-utilized natural gas plants.

Although the rule does not propose CO2 reductions from any baseline year, EPA has estimated the rule will result in a 30% reduction in CO2 emissions as compared to 2005.


The proposed  2030 goal for North Carolina is  992 lbs CO2/ MWh. By comparison, North Carolina’s electric generating units reported 2012  emissions  of  1647 lbs CO2/ MWh. (Source: Congressional Research Service report.) The EPA rule would require North Carolina to reduce CO2 emissions from:

1647 lbs of CO2 per megawatt hour  of electricity generated by fossil fuel EGUs


992 lbs of CO2 per megawatt hour of electricity generated by fossil fuel EGUs + estimated new renewable energy generation+ new or preserved nuclear capacity+ electricity generation avoided by energy efficiency measures

The Clean Power Plan goal does not require  North Carolina power plants to reduce CO2 emissions by 40%.  The rule requires the state’s  electric generation  system  as a whole to  meet demand for electric power at a 40% lower rate of CO2 emissions.


The draft EPA  rule  requires  states to  use four “building blocks” to comply; the building blocks correspond to the factors EPA used to calculate each state’s  CO2 reduction goal:

1. Increased heat efficiency at EGUs —  EPA has  assumed each EGU can achieve  6% improvement in heat efficiency.

2. Increased “dispatch” of power generation from higher emission coal-fired units to lower emission Natural Gas Combined Cycle (NGCC) plants —   EPA has assumed every NGCC  unit can be operated at 70% utilization.

3. Increased generation of electricity from renewable sources and new or preserved nuclear generation.  EPA has estimated the  potential for growth in renewable energy generation and new or preserved nuclear generation individually for each state.

4. Energy efficiency measures to lower demand,  measured by  megawatt hours of generation avoided. EPA set a  goal of increasing demand-side efficiency by 1.5% annually.

The individual building block goals set out for each state are not requirements. EPA  used  these assumptions and estimates  to calculate  each state’s  CO2 reduction goal, but  the rule allows a state to weight the  building blocks differently in  its  compliance plan.  For example,  difficulty meeting EPA’s expectations  for demand-side energy efficiency can be offset  by increasing renewable energy generation (or vice-versa).


Media reports have  reflected a lot of confusion about the impact of the proposed rule on states like North Carolina that have already taken significant steps to increase renewable energy and energy efficiency.   The proposed federal rule actually stresses  reliance on programs already in place and gives the states  credit for expanded renewable energy generation or growth in energy efficiency as a result of  existing programs.

In talking about the final state emission rate goals,  the rule notes that  “EPA is also proposing that measures taken by a state or its sources after the date of this proposal, or programs already in place, and which result in CO2 emission reductions at affected EGUs during the 2020-2030 period, would apply toward achievement of the state’s CO2 goal.” 

The rule makes a similar statement about renewable energy generation:  “We note that with the exception of hydropower, the renewable energy generation levels represent total amounts of renewable energy generation, rather than incremental amounts above a particular baseline level. As a result, this RE generation can be supplied by any RE capacity regardless of its date of installation.”

Table 6 in the proposed rule  shows North Carolina’s 2012 renewable energy generation as 2% and a proposed final 2030 goal for North Carolina of  10%.  The  N.C. Utilities Commission has reported that North Carolina electric utilities met the first state Renewable Energy Portfolio Standard (REPS) goal of  3% of retail electricity sales in 2012. The final goal under the existing state law will be 10% of retail sales for electric membership corporations/ municipal systems  (by 2018) and 12.5% of retail sales for the electric public utilities (by 2021).  Under the EPA rule, the state will get credit for any new or expanded renewable energy generation in 2014 or later as a result of the existing state REPS requirement.

Since the state REPS goal requires electric utilities to continue to increase renewable energy generation and energy efficiency through 2021,  the increases realized between 2014 and 2021 will also move North Carolina toward the federal goal. To know whether the proposed carbon rule will require the state to do more on renewable energy, the state will need a gap analysis.  The analysis will have to separate  renewable energy generation from energy efficiency savings; the two have been combined in the state REPS goal, but are calculated separately under the federal rule.

The federal rule sets a goal of having every state achieve a 1.5% annual incremental savings based on  demand-side energy efficiency measures.  EPA assumes that states already realizing  a 1.5% in annual incremental savings  will continue  and  maintain that rate through 2029 — giving states that engaged in energy efficiency measures early full credit for the incremental energy savings achieved through existing programs. To understand how close North Carolina may already be to meeting the  carbon rule’s  energy efficiency goal, the state will need to calculate the incremental annual  demand side savings that can be attributed to the state REPS goal and  add incremental savings associated with other energy efficiency programs (such as energy efficiency standards incorporated in the State Building Code).


The big  question to be answered is this: How far will North Carolina’s existing renewable energy and energy efficiency programs go toward closing the gap between 1647 lbs CO2/MWh generated by EGUs that burn fossil fuels  and 992 lbs CO2/ MWh generated by power plants+ renewable energy + new/preserved nuclear + generation avoided by energy efficiency?

It appears the remaining gap may be small, giving  North Carolina  an advantage over states that haven’t adopted policies supporting renewable energy generation and energy efficiency.   If so, the advantage will be economic as well as environmental by holding down increases in state energy costs.


Text of the Clean Carbon Rule (from the June 18, 2014 Federal Register notice)

Congressional Research Service Report: State CO2 Emission Rate Goals in EPA’s Proposed Rule for Existing Power Plants, Jonathan Ramseur, Specialist in Environmental Policy, July 21, 2014.

2013 NC Utilities Commission Annual Report Regarding Renewable Energy and Energy Efficiency Portfolio Standard in North Carolina

N.C. Coal Ash Bill Becomes Law

September 24, 2014. On September 20, Senate Bill 729 (the Coal Ash Management Act) became law without the Governor’s signature. Governor Pat McCrory had expressed concern that a provision in the bill giving legislators the majority of appointments to the new Coal Ash Management Commission violated the constitutional doctrine of separation of powers. Rather than  veto the bill, the governor allowed the bill to become law without his signature and signaled an intent to ask the N.C. Supreme Court for an advisory opinion on the constitutionality of the appointments provision.

In the meantime,  Senate Bill 729  — now Session Law 2014-122 — makes a number of  immediate changes to state law  and sets in motion a  15-year  process for remediating and then closing thirty-three existing coal ash impoundments. An earlier post provided an overview of the  final bill and now attention will turn to implementation.


  • Effective October 1, 2014 the law prohibits utilities from building new impoundments or expanding existing impoundments for disposal of coal ash.
  • Also effective October 1, 2014, the law  prohibits use of impoundments at closed electric generating facilities for coal ash disposal. The provision prevents a utility from transporting coal ash from an active generation plant to a closed facility for disposal in an impoundment.
  • By October 1, 2014, the utilities must submit a survey to the Department of Environment and Natural Resources (DENR) identifying all drinking water wells within 1/2 mile down-gradient of an impoundment.
  • The law requires the utilities to submit groundwater assessment plans  and  maps showing discharges to surface waters (both permitted and unpermitted) for all 33 impoundments by December 31,  2014.  The maps and groundwater assessment plans represent the first in a series of steps leading to remediation of  groundwater contamination around the impoundments and elimination of unpermitted discharges to surface waters.
  • S.L. 2014-122 sets much more stringent standards for use of coal ash in large structural fill projects and puts a moratorium on smaller structural fill projects to study appropriate standards for those projects.  (“Structural fill” projects involve the use of coal combustion residuals as fill material to level a construction site, build up a road bed, or otherwise change site elevation before construction.) The new standards include setbacks from surface waters and drinking water wells; a requirement for synthetic liners and a leachate collection system; a four-foot separation between the lowest level of fill and groundwater; financial assurance; and standards for closure.
  • Amendments to the state Dam Safety Act require dam owners to  prepare an emergency action plan for each high and intermediate risk impoundment. (The provision applies to all impoundments regulated under the Dam Safety Act and not  just coal ash impoundments.)
  • Dam Safety Act amendments also set minimum requirements for inspection of coal ash impoundment by the utilities   (weekly and following storms) and by DENR  (annually).
  • A new fee imposed on electric utilities that own coal ash impoundments will fund regulatory activities at DENR and the new Coal Ash Management Commission. The law authorizes use of the revenue to create  5 positions in the Department of Public Safety to support the Coal Ash Management Commission and 25 new positions in DENR.
  • S.L. 2014-122 amends state law  to require notice to DENR of any wastewater spill to  surface waters  as soon as practicable, but no more than 24 hours after the spill reaches surface waters.  The law also shortens the time allowed to provide notice to the public  from 48 hours to 24 hours.
  •  S.L. 2014-122 repeals most of a controversial 2013 regulatory reform provision on groundwater remediation by eliminating statutory language that: 1.  created a presumption that the groundwater compliance boundary around a waste disposal site should be at the property boundary;  and 2. limited DENR’s ability to require measures within the compliance boundary to control groundwater contamination. A provision in the same section of  S.L. 2014-122  created a new controversy, however, by reversing a recent superior court decision interpreting state groundwater remediation rules. (For an explanation of the controversy, see the earlier post.)
  • The law creates new civil and criminal penalties for violation of laws related to management of coal ash.

The law also requires a number of actions over the next year intended to  expand beneficial uses of coal ash. The most unusual provision requires the electric utilities  to issue a request for proposals by December 31, 2014 for:

(i) the conduct of a market analysis for the concrete industry and other industries that might beneficially use coal combustion residuals and coal combustion products; (ii) the study of the feasibility and advisability of installation of technology to convert existing and newly generated coal combustion residuals to commercial-grade coal combustion products suitable for use in the concrete industry and other industries that might beneficially use coal combustion residuals; and (iii) an examination of all innovative technologies that might be applied to diminish, recycle or reuse, or mitigate the impact of existing and newly generated coal combustion residuals.


S.L. 2014-122 gives  the impoundments at four coal-fired plants (Dan River Steam Station, Riverbend Steam Station, Asheville Steam Electric Generating Plant and the Sutton Plant) priority for final closure. The law then directs DENR to classify  the other 10 impoundment sites in the state based on risk by the end of 2015. Under  the law,  final closure of impoundments classified as high or intermediate risk will require removal of all coal ash for disposal in a lined industrial landfill (on or off-site) or for  beneficial reuse. Impoundments classified as low risk  have the additional closure option of capping the coal ash in place as long as the closure plan includes measures that will prevent groundwater contamination beyond the compliance boundary.

S.L. 2014-122 sets final closure deadlines based on the risk classification — December 31, 2019 for high risk impoundments; December 31, 2024 for intermediate risk impoundments and December 31, 2029 for low risk impoundments.


S.L. 2014-122 marks a real and significant change in environmental policy — forcing a transition away from use of wet impoundments for coal ash disposal and toward more protective methods of disposal and safe reuse.   In support of that policy decision, the law provides statutory timelines  for assessment, remediation and final closure of all 33 impoundments and  new resources for state oversight.

Even with resources to implement S.L. 2014-122, it will be difficult to hold to the timelines in the law without an ongoing commitment on the part of the General Assembly, DENR and the electric utilities. Any number of bureaucratic and technical problems could delay or derail implementation of the law.  (The thirty new positions authorized under the bill do not magically appear  when the bill becomes law — getting from legislative authorization of a new position to having a person  on the job  usually  takes months.) The goals of the law won’t be met if the state too easily gives in to unnecessary delays.

Decisions on remediation; classification of impoundments for closure; and approval of closure plans will present a different kind of challenge. There will be an inevitable tension between the utilities’ desire to keep the  cost of compliance  low and the state’s responsibility to protect  groundwater and surface water resources. The bill creates another potential source of tension by giving the new Coal Ash Management Commission  — not DENR — the authority to make final decisions on classification of impoundments and approval of closure plans. The Commission will have a very small staff and the law does not require any commission member to have expertise in  groundwater hydrology or water quality  –  likely to be critical in prioritizing sites for closure and approving closure plans.  With good luck and the right appointments, the arrangement  might work; or it could  lead to  conflict and overly politicized decision-making.

Regulatory Reform 2014

September 23, 2014.  Late last week, Governor Pat McCrory signed Senate Bill 734 (the Regulatory Reform Act of 2014)  on the final day to either sign or veto the bill.  The bill, now Session Law 2014-120, includes both substantive  changes to environmental laws and  amendments to the state Administrative Procedures Act  affecting environmental rule-making and administrative appeals. Below, some of the more significant  environmental provisions; a future post will look at the administrative law changes.

Air Quality: Open burning and fireplaces. Section 24 of Senate Bill  734 eliminates the need for  a state air quality  permit for open burning of leaves, stumps, logs, tree branches, yard trimmings under certain circumstances.  It  also  prohibits a city from banning or limiting open burning of debris in the city’s  1-mile extra-territorial jurisdiction unless the city provides yard waste pickup or access to drop off centers in the area to the same extent provided to residents in the city.  These provisions are the latest in a series of  legislation actions over the last three years to reduce  regulation of open burning.

Section 24(h) prohibits local air pollution control programs and the state from regulating any combustion heater, fireplace, etc. in a private dwelling except as required by federal law. This appears to be a preemptive move; I am not aware of any state or local air quality initiative  to regulate residential fireplaces and heaters.

Coastal Development:  Coastal stormwater;  inlet hazard areas; and permit appeals.

Coastal Stormwater. Section  25 of   Senate Bill  734 extends a  grandfathering provision in the coastal stormwater rule,  15A NCAC 02H .1005,   to expansion of the grandfathered development onto adjoining  property.

Inlet hazard areas. Since ocean Inlets  often move in response to changing nearshore condition and cause  accelerated  shoreline change, state coastal development rules have long put additional density and size limitations on development in  designated inlet hazard areas. In 2012, the General Assembly directed the Coastal Resources Commission (CRC) to study the Cape Fear River Inlet Hazard Area.  Within the past year,  the CRC expanded the review  to all  inlet hazard areas. Although the CRC review has not been completed,   Senate Bill 734 preemptively  removes some coastal shorelines  from existing inlet hazard area designations:

(1)  An inlet hazard area associated with an inlet that has been closed for at least 15 years.  The provision applies only to Mad Inlet in Brunswick County. The inlet originally separated Sunset Beach from Bird Island to the south, but  closed naturally in 1998.  The CRC  had already amended coastal management  rules to remove the Mad Inlet hazard designation earlier this year.

(2)  Inlet hazard area designations that no longer include the current inlet location due to shoreline change.  This provision also applies to Mad Inlet, but it is not clear that the impact will be limited to Mad Inlet. Other inlets have moved due to natural shoreline change or  engineered inlet relocation projects and  a comparison of current inlet locations to the corresponding inlet hazard area will be necessary to fully understand the potential impact of the provision.

(3)  The inlet hazard area surrounding an  inlet providing access to a State Port via a channel maintained by the United States Army Corps of Engineers. This provision eliminates the inlet hazard area designated around the mouth of the Cape Fear River at the entrance to the  Wilmington port,  which now includes part of the Bald Head Island shoreline.  The Village of Bald Head Island had pushed for removal of the inlet hazard area designation.

Shorelines  removed from  an inlet hazard area will be regulated instead under the general standards for  development on ocean and estuarine shorelines.

Coastal Area Management Act (CAMA) Permit Appeals. Section 23 of  the bill  eliminates  the automatic stay of a CAMA permit that has been appealed by a third party.  Under the amended law, a petitioner appealing the issuance of a CAMA permit will have to request an administrative law judge to stay the permit pending appeal. The amendment makes the CAMA appeal statute consistent with stay provisions in the state Administrative Procedures Act, but third parties  seeking to appeal a CAMA permit will continue to face a hurdle that is not imposed on other petitioners  —  the need for a preliminary determination by the CRC that the appeal has merit.

Environmental Permitting. Most permitting programs apply the standards in effect at the time of the permit decision. If  a rule or ordinance  changes during review of a permit application, the project may have to be  modified to meet the new standard.  In those circumstances, Section 16 of Senate Bill 734  now allows the permit applicant to choose whether to construct under the new standard or the old standard. The provision applies to development permits issued under state environmental laws or under  local ordinances. The new law does not define “development permit”, but clearly excludes zoning ordinances from the “permit choice” option.  The provision does not  recognize any exception based on requirements of federal law.

Engineered Plans. Section 29  of Senate Bill 734 makes a number of changes in the way state and local government permit reviewers interact with professional engineers  responsible for  design of a  proposed project. The  legislature’s Environmental Review Commission recommended the provision. See the section on review of engineered plans in an earlier post for more detail and  background on the conflict between PEs and state/local permit reviewers.

Onsite Wastewater Systems: Innovative systems and permitting changes

Innovative wastewater systems. Section 28 of Senate Bill  734 changes the law on approval of innovative onsite wastewater systems using polystyrene aggregate as a substitute for the gravel traditionally used in trenches for dispersion lines. “Innovative” systems do not meet established standards for onsite wastewater systems and require approval by the Department of Health and Human Services (DHHS). The new provision prevents DHHS and the Commission for Public Health from conditioning approval of a system using polystyrene synthetic aggregate on using a certain particle or bulk density.  The provision also requires DHHS and the Commission to rescind and reissue any  approval that may have included  those conditions. The legislative record does not  reflect  any  discussion of the density  conditions  — either the reason the conditions had been imposed or the effect that removal of the density  conditions may have on the performance of the wastewater systems.

Permitting. Section 40  expands the current permitting law to  cover ground absorption systems and removes the 5-year limit on a permit issued for installation of an on-site wastewater system. Under the provision, the permit holder would not require a new authorization even  if   standards for those systems have changed.

Parks. Section 31 of the bill allows the Secretary of Environment and Natural Resources to waive the 25 mile per hour speed limit in state parks for special events and  gives  the Commissioner of Agriculture the same authority in state forests. Media reports during the legislative session indicated the waiver had been requested by groups interested in using  a state park for private race events.  See a  report by the Raleigh News and Observer.

Water Quality: Isolated wetlands and stormwater. 

Isolated Wetlands. Section 54  raises the permitting threshold  for disturbance of isolated wetlands.  (See an earlier post for an explanation of the term “isolated wetlands”.) West of Interstate 95 (the unofficial dividing line between eastern and  piedmont/western  N.C. ), the permitting threshold has been raised  from 1/10 acre to 1/3 acre. East of I-95, the permitting threshold has been raised from 1/3 acre to 1 acre.    During the legislative debate, DENR indicated that raising the permitting threshold to 1 acre east of I-95 would effectively eliminate permitting requirements for isolated wetlands in the eastern part of the state. The bill also  reduces  the mitigation ratio for  all wetland impacts from 2:1 to  1:1 and directs DENR to study the definition of isolated wetlands and whether mountain bogs  should be regulated differently  than other isolated wetlands.

StormwaterSection 45 of Senate Bill 734  reverses  a 2013 regulatory reform. The Regulatory Reform Act of 2013 (Session Law 2013-413)  changed   stormwater  standards to  treat gravel areas as “pervious” and to exclude gravel from the calculation of “built-upon” area on a development site.  Since the amount of built-upon area determines the level of stormwater control required, developers had  pushed for exclusion of gravel areas from the calculation as a way to reduce stormwater management requirements. The 2013  provision  also directed the legislature’s Environmental Review Commission (ERC)  to study state stormwater programs “including how partially impervious surfaces are treated in the calculation of built-upon area under those programs”.

The ERC study group  encountered an unexpected complication — the lack of consensus on  the definition of  “gravel” had  created uncertainty  about implementation of the 2013 provision.   Instead of moving  on to the next reform requested by developers, the ERC  focused  on defining gravel and found that gravel  may not be pervious depending on the  nature of the aggregate material and the underlying substrate.   On recommendation of the ERC,  Section 45 of Senate Bill 734 effectively repeals the 2013 provision and directs the Department of Environment and Natural Resources (DENR)  to contract with N.C. State University for a study of the pervious/impervious qualities of different types of aggregate materials.

Water Supply: Interbasin transfer.  Sec. 37 of Senate Bill  734  extends an expedited interbasin transfer  approval process (originally created for certain coastal counties) to allocation of water from  reservoirs managed by the U.S. Army Corps of Engineers.  The intent may be to speed approval of an  interbasin transfer that would allow the City of Raleigh to take drinking water from Kerr Lake.