Proposed Oil and Gas Resources Regulations

Proposed Oil and Gas Resources Regulations
PROPOSED ACTION ON REGULATIONS
94
Title 17
DEPARTMENT OF BUDGET
AND MANAGEMENT
Title 26
DEPARTMENT OF THE
ENVIRONMENT
Subtitle 05 COUNCIL ON
MANAGEMENT AND
PRODUCTIVITY
Subtitle 19 OIL AND GAS RESOURCES
17.05.01 Competitive
Program
Re-Engineering
26.19.01 Oil
Production
Pilot
Authority: State Finance and Procurement Article, §§18-101—18-104,
Annotated Code of Maryland
Notice of Proposed Action
and
Gas
Exploration
and
Authority: Environment Article, §14-103, Annotated Code of Maryland
Notice of Proposed Action
[15-001-P-I]
The Secretary of the Environment proposes to repeal existing
Regulations .01—.15 and adopt new Regulations .01—.58 under
COMAR 26.19.01 Oil and Gas Exploration and Production.
[15-023-P]
The Secretary of Budget and Management proposes to repeal
Regulations .01 — .08 under COMAR 17.05.01 Competitive ReEngineering Pilot Program.
Statement of Purpose
The purpose of this action is to repeal COMAR 17.05.01. These
regulations were promulgated to support the statute that created the
Competitive Re-Engineering Pilot Program, State Finance and
Procurement Article, §§18-101 — 18-104, Annotated Code of
Maryland. That statutory authority abrogated September 30, 2003.
Comparison to Federal Standards
There is no corresponding federal standard to this proposed action.
Estimate of Economic Impact
The proposed action has no economic impact.
Economic Impact on Small Businesses
The proposed action has minimal or no economic impact on small
businesses.
Impact on Individuals with Disabilities
The proposed action has no impact on individuals with disabilities.
Opportunity for Public Comment
Comments may be sent to Jennifer P. Hine, Personnel Director,
Department of Budget and Management, 301 W. Preston Street,
Room 602, Baltimore, MD 21201, or call 410-767-4718, or email to
[email protected], or fax to 410-333-5262. Comments will
be accepted through February 9, 2015. A public hearing has not been
scheduled.
T. ELOISE FOSTER
Secretary of Budget and Management
Statement of Purpose
The purpose of this action is to update the regulations to address
new technologies.
These changes will establish new oil gas exploration and
production standards. The new standards for oil and gas exploration
and production in Maryland are needed to provide adequate
protection for public health, safety, the environment and natural
resources. These standards are at least as protective, and in some
cases more protective, than those in place currently in other states.
The standards will provide a suite of best practices that are to be
followed for oil and gas production in the Marcellus Shale in
Maryland.
Background
The Marcellus Shale is a black shale, or rock formation, found
throughout the northern Appalachian Basin. The Marcellus Shale
formation underlies New York, Pennsylvania, Ohio, West Virginia
and western Maryland. In 2009, the Department of Energy estimated
262 trillion cubic feet of natural gas exists in the Marcellus Shale,
making it the largest onshore Natural Gas Reserve in the United
States. In Maryland, the Marcellus Shale formation is located within
western Maryland from Washington, Allegany and Garrett Counties.
The only anticipated areas of gas production in the Marcellus Shale
are western Allegany and Garrett Counties.
On June 6, 2011, Governor Martin O’Malley signed Executive
Order 01.01.2011.11, establishing the Marcellus Shale Safe Drilling
Initiative. The Executive Order directs the Maryland Department of
the Environment (MDE) and the Department of Natural Resources
(DNR) to assemble and consult with an Advisory Commission in the
study of specific topics related to horizontal drilling and hydraulic
fracturing in the Marcellus Shale. The Advisory Commission was
established to assist State policymakers and regulators in determining
whether and how gas production from the Marcellus Shale in
Maryland can be accomplished without unacceptable risks of adverse
impacts to public health, safety, the environment, and natural
resources. The Advisory Commission includes a broad range of
stakeholders, including elected officials from Allegany and Garrett
Counties, two members of the General Assembly, representatives of
the scientific community, the gas industry, business, agriculture,
environmental organizations, citizens, and a State agency. A
representative of the public health community was added in 2013.
Since its inception the Advisory Commission has met 35 times.
Most meetings were in Allegany or Garrett Counties, but several
were held in Hagerstown, Annapolis and Baltimore. The Departments
provided written information and briefings to the Advisory
Commission on issues relating to high volume hydraulic fracturing
MARYLAND REGISTER, VOLUME 42, ISSUE 1, FRIDAY, JANUARY 9, 2015
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(HVHF). Speakers representing the scientific community, industry
and agencies from Maryland and other states presented information
to the Advisory Commission and the Departments. The
Commissioners were able to visit active drilling sites. The
Departments consulted with the federal government and neighboring
states regarding policy, programmatic issues and enforcement
experiences. The Commissioners themselves shared information and
brought their expertise to bear.
The Executive Order tasked MDE and DNR, in consultation with
the Advisory Commission, with conducting a three-part study and
reporting findings and recommendations. The completed study
includes:
i. findings and related recommendations regarding sources of
revenue and standards of liability for damages caused by gas
exploration and production;
ii. recommendations for best practices for all aspects of natural gas
exploration and production in the Marcellus Shale in Maryland; and
iii. a final report with findings and recommendations relating to
the impact of Marcellus Shale drilling including possible
contamination of ground water, handling and disposal of wastewater,
environmental and natural resources impacts, impacts to forests and
important habitats, greenhouse gas emissions, and economic impact.
The completed study has informed this action to update the
standards for oil and gas exploration and production. Many of the
updated standards included in this regulatory action were included
among the recommendations in the completed study.
Affected Sources
This action directly impacts oil and gas exploration and production
companies and their contractors that work in Maryland. There will
also be impacts to trucking companies engaged to work on behalf of
the oil and gas companies. Additionally, there could be impacts to
mineral rights owners in Garrett and Allegany Counties.
Requirements
This is a comprehensive regulatory action to address the potential
impacts to public health, safety, the environment and natural
resources from HVHF in the Marcellus Shale in Maryland. The
updated regulatory standards included in this action will require a
suite of best practices be followed for oil gas exploration and
production. These best practices will provide superior results to those
achieved by other methods and techniques. These best practices are
as protective, or more protective, than those in place currently in
other states.
The following are requirements that will be imposed on affected
sources by these regulations:
• Use of a Comprehensive Development Plan (CDP) - Designed to
address the larger, landscape-level issues and cumulative effects. This
comprehensive planning tool will allow for gas development
activities to be considered in an area rather than considering each
well individually. This includes the consideration of the placement of
well pads, roads, pipelines and other ancillary equipment for a large
area. The CDP is mandatory except for a limited number of
exploratory wells, and will be a prerequisite to an application for a
well permit. Once the CDP is approved, applications for individual
wells consistent with the approved plan could be made.
• Public notification and opportunity for public hearing - The
application for an individual well permit includes public notice and
opportunity for public hearing once the Department determines the
application is complete. The Department will provide written notice
of its final decision to the applicant, any participants who attended a
public informational hearing, persons who commented on the
application, and all landowners, royalty owners, and owners of
mineral, oil, and gas rights within 1,000 feet of the proposed well.
• Environmental Assessment and baseline monitoring - An
application for a permit to drill a well must include an Environmental
Assessment and two years of baseline monitoring in the vicinity of
the well pad.
• Location restrictions and setbacks - For wells and well pads,
including restrictions based on: topography and geology; location
within certain reservoirs and drinking water protection areas;
proximity to certain natural features; proximity to boundary lines;
and proximity to certain occupied dwellings.
• Detailed plans for individual wells - The application for an
individual well permit will require detailed plans for all activities,
from construction of the access road through closure and restoration
of the site. The elements of the plan must meet or exceed standards
for engineering, design and environmental controls that are
recommended in these standards. The engineering, design, and
environmental controls and standards include requirements for:
- Drilling
- Stormwater management;
- Sediment and erosion control;
- Wellpad construction;
- Access roads;
- Freshwater storage;
- Chemical use, storage, and handling;
- Chemical disclosure;
- Radioactive materials
- Transportation and truck traffic;
- Protection of Sensitive Aquatic Resources
- Protection of freshwater aquifers;
- Control and reporting of air emissions;
- Use of engines and compressors;
- Blowout prevention;
- Leak detection and repair;
- Well construction, casing, and cement;
- Integrity testing;
- Monitoring during drilling and high volume hydraulic fracturing;
- Site security;
- Management of drilling fluids, simulation fluids and produced
water;
- Gathering lines and pipelines;
- Flaring;
- Noise;
- Lighting;
- Spill prevention, control and countermeasures and emergency
response plan;
- Ongoing monitoring and corrective measures;
- Invasive species;
- Site reclamation; and
- Wastes and wastewater.
• Financial Assurance - These regulations also include
requirements for liability insurance, environmental pollution liability
insurance, and a performance bond, a blanket bond, cash, a
certification of deposit, or a letter of credit relating to proper
abandonment of wells.
• Plugging of oil or gas wells - These regulations include detailed
requirements for plugging of an oil or gas well.
• Bond performance and release procedures - The regulations
include requirements for oil and gas bond performance and release
procedures.
• Statutory, Regulatory, or Permit violations - The regulations
include Departmental authority and potential actions against a person
who violates either statutory, regulatory, or permit provisions relating
to oil and gas exploration and production.
Comparison to Federal Standards
There is no corresponding federal standard to this proposed action.
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Estimate of Economic Impact
I. Summary of Economic Impact. The proposed regulations for
oil and gas exploration and production will economically impact
many different parties, both positively and negatively. These
economic impacts cannot be quantified, but are discussed in detail
below.
II. Types of Economic
Impact.
A. On issuing agency:
(1) Program
implementation
(2) Funding of program
implementation
B. On other State agencies:
(1) Department of
Natural Resources
(2) Department of
Natural Resources
C. On local governments:
(1) Road improvements
(2) Road improvements
and maintenance
Revenue (R+/R-)
Expenditure
(E+/E-)
Magnitude
(E+)
Indeterminable
(R+)
Indeterminable
(E+)
Indeterminable
(R+)
Indeterminable
(E+)
Indeterminable
(R+)
Indeterminable
Benefit (+)
Cost (-)
Magnitude
D. On regulated industries or trade groups:
(1) Oil and Gas
Companies—Large
(-)
Indeterminable
(2) Oil and Gas
Companies—Small
(-)
Indeterminable
(3) Trucking
Companies
(-)
Indeterminable
E. On other industries or trade groups:
(1) Environmental
Consultants
(+)
Indeterminable
(2) Laboratories
(+)
Indeterminable
(3) Tourism
(+)
Indeterminable
(4) Real Estate
(+)
Indeterminable
F. Direct and indirect effects on public:
(1) Health Benefits
(+)
Indeterminable
(2) Drinking Water
Protection
(+)
Indeterminable
(3) Natural Resource
Protection
(+)
Indeterminable
(4) Environmental
Protection
(+)
Indeterminable
III. Assumptions. (Identified by Impact Letter and Number from
Section II.)
A(1). There will be an economic impact to the Department of the
Environment (MDE). The regulatory and permitting requirements
will require additional work by Department staff. How much
additional work would vary depending on the level of drilling activity
in Maryland’s portion of the Marcellus Shale formation. Some of the
additional work for the Department would include additional work
reviewing: Comprehensive Development Plans (CDPs); the required
two years of baseline data; and more detailed permit applications.
There would also be additional work to monitor compliance with
permit conditions. Any additional costs to the Department for this
work cannot be estimated.
A(2). Environment Article, §14-105, Annotated Code of Maryland
authorized the Department to assess permit and production fees in an
amount necessary to operate the regulatory program, with a provision
for annual adjustment.
B(1). There will be an economic impact to the Department of
Natural Resources (DNR). How much additional work would vary
depending on the level of drilling activity in Maryland’s portion of
the Marcellus Shale formation. Under the proposed regulations, DNR
will have responsibilities concerning evaluation of Comprehensive
Development Plans. In addition, DNR has a consultative role with
MDE for various activities specified in the proposed regulations.
Additional costs to DNR for these activities cannot be estimated.
B(2). The proposed regulations provide for reimbursement of
DNR by MDE for some expenses associated with evaluation of
proposed CDPs.
C(1). There is potential for economic impacts to local
jurisdictions. The regulations provide for the option for local
jurisdictions to enter into agreements with drilling companies to
make road improvements that are necessary as a result of drilling
activity. This is voluntary for local jurisdictions, but it is likely that
some of the jurisdictions will undertake this activity, which will lead
to added costs. Any additional costs to local jurisdictions cannot be
estimated.
C(2). There is a potential for a positive economic impact to local
jurisdictions if roads are improved or maintained at the cost of the
exploration or drilling company.
D(1). The largest economic impact will be to oil and gas
exploration and production companies that work in Maryland. These
companies will have to meet the more stringent oil and gas
exploration and production regulations. These regulations are more
stringent than what is currently required in Maryland regulations, and
as stringent, or more stringent, than what is required in other states
that were surveyed. Some of these additional requirements will result
in negligible additional costs to the oil and gas companies because
many of the best practices that will be required by these regulations
have become fairly common industry practices among the larger
companies that engage in this type of activity. The major added costs
to these larger companies would be the costs related to the
Comprehensive Development Plan, two years of baseline monitoring
before a well can be drilled, ongoing monitoring during drilling,
hydraulic fracturing, and production, and any additional testing
required by the Department. Any additional costs to large companies
or smaller companies from these requirements cannot be estimated.
There will also be added costs to oil and gas companies to comply
with the financial assurance provisions of the regulations. These
companies must have liability insurance, environmental pollution
liability insurance, and a performance bond, a blanket bond, cash, a
certificate of deposit, or a letter of credit. Larger companies will
likely avoid the added costs associated with these requirements by
meeting the alternative financial test.
D(2). The largest economic impact will be to oil and gas
exploration and production companies that work in Maryland. These
companies will have to meet the more stringent oil and gas
exploration and production regulations. These regulations are more
stringent than what is currently required in Maryland regulations, and
as stringent, or more stringent, than what is required in other states
MARYLAND REGISTER, VOLUME 42, ISSUE 1, FRIDAY, JANUARY 9, 2015
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that were surveyed. Some of these additional requirements will result
in negligible additional costs to the oil and gas companies because
many of the best practices that will be required by these regulations
have become fairly common industry practices among the larger
companies that engage in this type of activity. The major added costs
to these larger companies would be the costs related to the
Comprehensive Development Plan, two years of baseline monitoring
before a well can be drilled, ongoing monitoring during drilling,
hydraulic fracturing, and production, and any additional testing
required by the Department. The smaller oil and gas companies will
likely have even larger additional costs to comply with the
regulations to the extent that the additional requirements are not
practices that they currently engage in. Any additional costs to large
companies or smaller companies from these requirements cannot be
estimated.
There will also be added costs to oil and gas companies to comply
with the financial assurance provisions of the regulations. These
companies must have liability insurance, environmental pollution
liability insurance, and a performance bond, a blanket bond, cash, a
certificate of deposit, or a letter of credit. It is unlikely that smaller
companies will be able to pass the alternative financial test. Any
additional costs to small companies from these requirements cannot
be estimated.
D(3). There is also the potential for economic impacts to trucking
companies that contract with oil and gas companies to transport
materials to and from the well sites. All trucks transporting waste
materials from the site must have a Global Positioning System (GPS)
to track the transport and disposition of these materials. This will be
an additional cost to trucking companies. This cost cannot be
estimated, as it depends on a number of factors, including the level of
drilling activity, the number of trucks in a company’s fleet, and
which trucks if any already have a GPS.
E(1). There will be positive economic impacts to environmental
consultants and laboratories for the additional work that will be
required by the regulations. It is likely that the drilling companies
will hire consultants and use laboratories to do all of the necessary
environmental assessments, baseline monitoring, ongoing
monitoring, testing and analytical procedures, and any other
environmental studies or assessments required by regulations or
permit. Any additional revenues to consultants cannot be estimated.
E(2). There will be positive economic impacts to environmental
consultants and laboratories for the additional work that will be
required by the regulations. It is likely that the drilling companies
will hire consultants and use laboratories to do all of the necessary
environmental assessments, baseline monitoring, ongoing
monitoring, testing and analytical procedures, and any other
environmental studies or assessments required by regulations or
permit. Any additional revenues to consultants cannot be estimated.
E(3). There will be positive economic impacts to real estate
professionals and tourism related businesses in Garrett and Allegany
Counties as a result of replacing the existing regulations with these
more stringent regulations. The protections included in these
regulations will help to minimize any negative impact to property
values that may result from drilling activity, which will positively
impact property owners and real estate professionals. Stronger
regulations for oil and gas drilling will also benefit the tourism
industry and tourism related businesses by ensuring better protection
of the natural environment which is the driver for much of the
tourism in these two Counties.
E(4). There will be positive economic impacts to real estate
professionals and tourism related businesses in Garrett and Allegany
Counties as a result of replacing the existing regulations with these
more stringent regulations. The protections included in these
regulations will help to minimize any negative impact to property
values that may result from drilling activity, which will positively
impact property owners and real estate professionals. Stronger
regulations for oil and gas drilling will also benefit the tourism
industry and tourism related businesses by ensuring better protection
of the natural environment which is the driver for much of the
tourism in these two Counties.
F(1). There will be positive economic impacts to the residents in
Garrett and Allegany Counties by enacting these more stringent
regulations. The regulations will minimize the impacts from drilling
to public health, safety, the environment and natural resources in
these two Counties. By minimizing these impacts, the general
citizenry of the two Counties will benefit from enhanced public
health protection and safety, including better protections for air
quality and sources of drinking water. Additionally, the natural
environment of the two Counties will be better protected, including
forests, rivers, streams and other water bodies, wildlife, flora and
fauna.
F(2). There will be positive economic impacts to the residents in
Garrett and Allegany Counties by enacting these more stringent
regulations. The regulations will minimize the impacts from drilling
to public health, safety, the environment and natural resources in
these two Counties. By minimizing these impacts, the general
citizenry of the two Counties will benefit from enhanced public
health protection and safety, including better protections for air
quality and sources of drinking water. Additionally, the natural
environment of the two Counties will be better protected, including
forests, rivers, streams and other water bodies, wildlife, flora and
fauna.
F(3). There will be positive economic impacts to the residents in
Garrett and Allegany Counties by enacting these more stringent
regulations. The regulations will minimize the impacts from drilling
to public health, safety, the environment and natural resources in
these two Counties. By minimizing these impacts, the general
citizenry of the two Counties will benefit from enhanced public
health protection and safety, including better protections for air
quality and sources of drinking water. Additionally, the natural
environment of the two Counties will be better protected, including
forests, rivers, streams and other water bodies, wildlife, flora and
fauna.
F(4). There will be positive economic impacts to the residents in
Garrett and Allegany Counties by enacting these more stringent
regulations. The regulations will minimize the impacts from drilling
to public health, safety, the environment and natural resources in
these two Counties. By minimizing these impacts, the general
citizenry of the two Counties will benefit from enhanced public
health protection and safety, including better protections for air
quality and sources of drinking water. Additionally, the natural
environment of the two Counties will be better protected, including
forests, rivers, streams and other water bodies, wildlife, flora and
fauna.
Economic Impact on Small Businesses
The proposed action has a meaningful economic impact on small
business. An analysis of this economic impact follows.
Small Business Analysis Worksheet
This worksheet is designed to assist the agency in determining if
and how the proposal impacts small businesses. Quantify the number
of affected small businesses and estimates of costs and benefits to
small businesses if possible. State Government Article §2-1505.2,
includes the following definitions which are relevant to the analysis:
“Economic impact analysis” means an estimate of the cost or the
economic benefit to small businesses that may be affected by a
MARYLAND REGISTER, VOLUME 42, ISSUE 1, FRIDAY, JANUARY 9, 2015
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regulation proposed by an agency pursuant to Title 10, Subtitle 1 of
this article.
“Small business” means a corporation, partnership, sole
proprietorship, or other business entity, including its affiliates, that:
(i) is independently owned and operated; (ii) is not dominant in its
field; and (iii) employs 50 or fewer full-time employees.
1a. Intended Beneficiaries. Who are the intended beneficiaries of
the proposed regulation? Are these intended beneficiaries primarily
households or businesses?
The intended beneficiaries of the proposed regulations are
residents of and visitors to Garrett and Allegany Counties. These
beneficiaries are primarily households. The proposed regulations will
have some indirect benefits to environmental consultants and
laboratories, as well as the real estate and tourism industries, but
these are not the primary intended beneficiaries.
1b. Intended Beneficiaries: Households. If households are the
primary intended beneficiaries, will the proposal affect their income
or purchasing power such that the volume or patters of their
consumer spending will change? If so, what directions of change
would you anticipate? Will these expected spending changes have a
disproportionate impact on small businesses? Can you descriptively
identify the industries or types of business activities that are
impacted?
The proposal should not materially affect the income or
purchasing power of households and thus will not change the volume
or patterns of their consumer spending.
1c. Intended Beneficiaries: Businesses. If businesses are the
intended beneficiaries, identify the businesses by industry or by types
of business activities. How will businesses be impacted? Are these
Maryland establishments disproportionately small businesses? If so,
how will these Maryland small businesses be affected? Can you
identify or estimate the present number of small businesses affected?
Can you estimate the present total payroll or total employment of
small businesses affected?
Companies in the tourism business will benefit because the
proposed regulations are much more protective of the environment
and natural resources than the existing regulations. Some of these
companies are small businesses. The Department does not have
information on the number or proportion of small businesses in the
total population of the tourism businesses.
2a. Other Direct or Indirect Impacts: Adverse. Businesses may not
be the intended beneficiaries of the proposal. Instead, the proposal
may direct or otherwise cause businesses to incur additional expenses
of doing business in Maryland. Does this proposal require Maryland
businesses to respond in such a fashion that they will incur additional
work-time costs or monetary costs in order to comply? Describe how
Maryland establishments may be adversely affected. Will Maryland
small businesses bear a disproportionate financial burden or suffer
consequences that affect their ability to compete? Can you estimate
the possible number of Maryland small businesses adversely
affected? (Note that small business compliance costs in the area of
regulation are the sum of out-of-pocket (cash) cost plus time costs –
usually expressed as payroll, akin to calculations for legislative fiscal
notes. Precise compliance costs may be difficult to estimate, but the
general nature of procedures that businesses must accomplish to
comply can be described.)
The proposed regulations affect oil and gas exploration and
production companies. Most of these companies are likely to be large
businesses. However, it is possible that some companies or their
contractors are small businesses. The Department does not have
information on the number or proportion of small businesses in the
total population of oil and gas businesses.
Oil and gas companies will have to meet the more stringent
regulations when conducting drilling operations in Maryland. The
regulatory requirements are more stringent than what is currently
required in Maryland regulations. Some of these additional
requirements will result in negligible additional costs to large oil and
gas companies because many of the requirements are already
included among common industry practices. The smaller oil and gas
companies will likely have larger additional costs to comply with the
regulations to the extent that the additional requirements are not
practices that they currently follow. Any additional costs to small oil
and gas businesses from these requirements cannot be estimated.
There will also be added costs to oil and gas companies to comply
with the financial assurance provisions of the regulations. Larger
companies will likely avoid the added costs associated with these
requirements by demonstrating that they comply with the alternative
financial test. It is unlikely that smaller companies will be able to
pass this alternative test, and thus will have to comply with the
addition financial assurance provisions of the regulations. Any
additional costs to these small businesses from these requirements
cannot be estimated.
There is also potential for economic impacts to trucking
companies that contract with oil and gas companies to transport
materials to and from the well sites. All trucks transporting these
materials must have a GPS to ensure the safe tracking and disposition
of these materials. This will be an additional cost to trucking
companies. These costs cannot be estimated. The Department does
not have information on the number or proportion of small businesses
in the total population of trucking companies.
2b. Other Direct or Indirect Impacts: Positive. Maryland
businesses may positively benefit by means other than or in addition
to changed consumer spending patterns. How may Maryland
businesses be positively impacted by this initiative? Will Maryland
small businesses share proportionately or disproportionately in these
gains? Can you estimate the possible number of Maryland small
businesses positively affected?
There will be positive economic impacts to environmental
consultants and laboratories for the additional work that will be
required by the regulations. It is likely that the drilling companies
will hire consultants and use laboratories to do all of the necessary
environmental assessments, baseline monitoring, ongoing
monitoring, testing and analytical procedures, and any other
environmental studies or assessments required by regulations or
permit. Any additional revenues to consultants cannot be estimated.
The Department cannot estimate the number or portion of small
businesses in the total population of environmental consulting
businesses likely to be positively impacted by these regulations.
There will also be positive economic impacts to real estate
professionals and tourism related businesses in Garrett and Allegany
Counties by enacting these more stringent regulations. The
protections included in these regulations will help to minimize any
negative impacts to property values that may result from drilling
activity, which will positively impact property owners and real estate
professionals. Stronger regulations for oil and gas drilling will also
benefit the tourism industry and tourism related businesses by
ensuring better protection of the natural environment which is the
driver for much of the tourism in these two Counties. The
Department cannot estimate the total number of portion of small
businesses in the total population of either real estate businesses or
tourism related businesses, although it is likely to be a large
proportion of the total population of both. The Department also
cannot estimate the total additional revenues to either of these types
of businesses.
3. Long-Term Impacts. There are instances where the longer run
economic impact effect from regulations differ significantly from
immediate impact. For example, regulations may impose immediate
burdens on Maryland small businesses to comply, but the overall
restructuring of the industry as a consequence of monitoring and
compliance may provide offsetting benefits to the affected small
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PROPOSED ACTION ON REGULATIONS
99
businesses in subsequent years. Can you identify any long run
economic impact effects on Maryland small businesses that over time
(a) may compound or further aggravate the initial economic impact
described above, or (b) may mitigate or offset the initial impact
described above?
No.
4. Estimate of Economic Impact. State Government Article 21505.2 requires that an agency include estimate, as appropriate,
directly relating to: (1) cost of providing goods and services; (2)
effect on the work force; (3) effect on the cost of housing; (4)
efficiency in production and marketing; (5) capital investment,
taxation, competition, and economic development, and (6) consumer
choice.
(1) Cost of providing goods and services: The Department cannot
determinate the additional costs of providing the services included in
the regulations.
(2) Effect on the work force: There will be better public health and
safety protections for oil and gas employees in Maryland from these
more stringent regulations. The Department cannot estimate this
benefit in dollar terms.
(3) Effect on the cost of housing: Traditionally there is a decrease
in home values when a home is located in close proximity to an oil or
gas well. The added protections in these regulations should serve to
limit the decrease in home values by affording homeowners better
public health, safety, and environmental protections. The extent of
this effect cannot be estimated.
(4) Effect on efficiency in production and marketing: None
expected.
(5) Capital investment, taxation, competition, and economic
development: The level of capital investment, taxation, competition,
and economic development resulting from these regulations is
unlikely to be significantly different than that under the current
regulations. The Department cannot estimate any changes in these
amounts.
(6) Consumer choice: None expected.
Impact on Individuals with Disabilities
The proposed action has no impact on individuals with disabilities.
Opportunity for Public Comment
Comments may be sent to Brigid Kenney, Senior Policy Advisor,
Maryland Department of the Environment, 1800 Washington
Boulevard, Baltimore, Maryland 21230-1720, or call 410-537-4187,
or email to [email protected], or fax to 410-537-3888.
Comments will be accepted through February 9, 2015. A public
hearing has not been scheduled.
Editor’s Note on Incorporation by Reference
Pursuant to State Government Article, §7-207, Annotated Code of
Maryland, the Guidelines for Administering Oil and Gas Activity on
State Forest Lands has been declared a document generally available
to the public and appropriate for incorporation by reference. For this
reason, it will not be printed in the Maryland Register or the Code of
Maryland Regulations (COMAR). Copies of this document are filed
in special public depositories located throughout the State. A list of
these depositories was published in 41:1 Md. R. 9 (January 10, 2014),
and is available online at www.dsd.state.md.us. The document may
also be inspected at the office of the Division of State Documents, 16
Francis Street, Annapolis, Maryland 21401.
.01 Definitions.
A. In this subtitle, the following terms have the meanings
indicated.
B. Terms Defined.
(1) Administratively Complete.
(a) “Administratively complete” means that the application
contains the information and supporting documents requested on the
application form.
(b) “Administratively complete” does not mean that the
application is complete for purposes of Regulation .16C of this
chapter.
(2) “Angular deviation and directional survey” means a well
survey that indicates, at frequent intervals, the amount and azimuth
that the hole has departed from vertical.
(3) “Annular space” means the area between the inner and
outer walls of two concentric casings and the area between the outer
casing and the wall of a borehole.
(4) “API” means American Petroleum Institute, a national
trade association that represents the oil and natural gas industry in
the United States that develops and publishes standards and other
documents.
(5) “Aquatic habitat” means all streams, rivers, seeps, springs,
wetlands, lakes, ponds, water reservoirs and 100 year floodplains.
(6) “Base fluid” means the continuous phase fluid used in the
makeup of a well stimulation treatment fluid.
(7) “Baseline monitoring” means gathering and reporting data
according to protocols developed jointly by the Departments of the
Environment and Natural Resources to characterize the condition of
air, ground water and surface water in the vicinity of a planned well
pad before site preparation and drilling.
(8) “Blowout” means an uncontrolled flow of gas, oil, or other
well fluids into the atmosphere, which may occur when formation
pressure exceeds the pressure applied to it by the column of drilling
fluid.
(9) “Blowout prevention equipment” means devices attached to
the top of the well casing that can be closed and shut off to control
pressure at the wellhead.
(10) “Brackish and salt water” means water with a total
dissolved solids concentration greater than 1,000 milligrams per
liter.
(11) “Bridge plug” means an expandable device used inside
the casing of a well to isolate certain zones or to seal the casing to a
shallower depth.
(12) “CAS” means Chemical Abstract Service.
(13) “Circulating medium” means any type of liquid, gas, or
slurry used as an agent to remove drill cuttings and to cool the bit.
(14) CO2 Equivalent Emissions (CO2e).
(a) “CO2 equivalent emissions (CO2e)” means the amount
of Greenhouse Gas emitted.
(b) “CO2 equivalent emissions (CO2e)”for methane is
computed by multiplying the mass amount of emissions, in tons per
year, by methane’s associated global warming potential.
(15) “Commingle production” means to mix hydrocarbons
from two or more pay zones in the same well.
(16) “Comprehensive Development Plan (CDP)” means a
document prepared by a person holding oil or gas interests
describing the person’s plans for exploration and production in the
Maryland portion of an oil- or gas-bearing formation for at least the
succeeding five years, and submitted to the State for review and
approval.
(17) “Comprehensive Development Plan applicant (CDPapplicant)” means a person submitting a Comprehensive
Development Plan to the Department for approval.
(18) “Conductor pipe” means a pipe used near the surface to
prevent unconsolidated material from caving or sloughing into the
hole.
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(19) “Coning” means the cone-shaped invasion of water
underlying oil or gas in an oil or gas reservoir or invasion of gas
overlying oil in a reservoir as the oil or gas is withdrawn from a well.
(20) “Critical Area” has the meaning stated in COMAR
27.01.01.01B.
(21) “Cuttings” means the fragments of rocks produced by the
drill bit during the drilling process and brought to the surface in the
drilling liquid.
(22) “Department” means the Department of the Environment.
(23) “Diesel fuel” means a substance with one of the following
Chemical Abstract Service Registry Numbers:
(a) 68334-30-5 Primary Name: Fuels, diesel;
(b) 68476-34-6 Primary Name: Fuels, diesel, No. 2;
(c) 68476-30-2 Primary Name: Fuel oil, No. 2;
(d) 68476-31-3 Primary Name: Fuel oil, No. 4; or
(e) 8008-20-6 Primary Name: Kerosene.
(24) “Directional drilling” means:
(a) Aiming wells at horizontally displaced bottom-hole
targets; and
(b) Intentional deviation of a borehole from the path it
would naturally take.
(25) “Discharge” has the meaning stated in COMAR
26.08.01.01B(20).
(26) Drilling Liquid.
(a) “Drilling liquid” means a fluid, such as mud or water,
circulated in a borehole to remove the drill cuttings from the hole
and to cool the drill bit.
(b) “Drilling liquid” does not include air or gas.
(27) “Dry hole” means a well that encountered no oil or gas of
commercial significance.
(28) “Environmental Assessment” means a document prepared
by an applicant for a gas and oil drilling and operating permit in
accordance with guidance from the Department and submitted with
an application for the permit and includes, at a minimum, a
discussion and evaluation of the possible ecological, aesthetic,
historic, cultural, economic, social, or health impacts of the planned
drilling and operating.
(29) “Explosives” means any chemical compound, mixture, or
device, the primary purpose of which is to function by explosion
through substantially instantaneous release of gas and heat, unless
the compound, mixture, or device is otherwise specifically classified
by the Interstate Commerce Commission or other federal agencies.
(30) “Flowback” means well stimulation treatment fluid and
formation water that comes to the surface through the borehole
during the first few days after well stimulation is completed.
(31) “FracFocus” means the national hydraulic fracturing
chemical registry managed by the Ground Water Protection Council
and the Interstate Oil and Gas Compact Commission.
(32) “Fresh water” means water with a total dissolved solids
concentration of 1,000 milligrams per liter or less.
(33) “Gas” means all natural gas and other fluid
hydrocarbons, not defined as oil, that are produced from a natural
oil or gas reservoir.
(34) “Gross vehicle weight rating (GVWR)) means the value
specified by the manufacturer as the maximum design loaded weight
of a single vehicle, consistent with good engineering judgment.
(35) “Heavy duty engine” means any engine which the engine
manufacturer could reasonably expect to be used for motive power in
a heavy-duty vehicle.
(36) “Heavy duty vehicle” means any motor vehicle that:
(a) Is rated at more than 8,500 pounds gross vehicle weight
rating (GVWR);
(b) Has a vehicle curb weight of more than 6,000 pounds; or
(c) Has a basic vehicle frontal area in excess of 45 square
feet.
(37) “High volume hydraulic fracturing” means all stages of a
stimulation treatment of a well by the pressurized application of more
than 80,000 gallons per stage or more than 300,000 gallons total of
hydraulic fracturing fluid and proppant to initiate or propagate
fractures in a geologic formation to enhance extraction or production
of oil or gas.
(38) “Hydraulic fracturing” means a stimulation treatment
performed on oil and gas wells in low-permeability oil or gas
reservoirs whereby specially engineered fluids are pumped at high
pressure and rate into the reservoir interval to be treated, causing
fractures to open.
(39) “Hydraulic fracturing fluid” means a mixture of a base
fluid, proppant and chemical additives injected through a well drilled
into an oil- or gas-bearing rock formation under high but controlled
pressure to initiate or propagate fractures in a geologic formation to
enhance extraction or production of oil or gas.
(40) “Impermeable” means that the permeability of the
material is less than or equal to 1 times 10-7 centimeters per second.
(41) “Injection well” means a well used for the subsurface
emplacement of fluids.
(42) “Irreplaceable Natural Area” means a site designated by
the Department of Natural Resources as a Tier 1 or Tier 2 under the
Biodiversity Conservation Network.
(43) “Killing the well” means overcoming downhole pressure,
in a well being drilled, through the use of drilling liquid or water.
(44) “Log” means a continuous record as a function of depth,
usually graphic and plotted to scale on a narrow paper strip, of
observations made on the rocks and fluids of the geologic section
exposed in a well bore.
(45) “Mechanical plug” means an expandable device placed in
a well to act as a water-tight, oil-tight, and gas-tight seal.
(46) “Nonporous material” means bentonitic mud, cement, or
equivalent materials approved by the Department which will retard
the movement of fluids.
(47) “Nontidal wetland” has the meaning stated in COMAR
26.23.01.01.
(48) “Oil” means crude petroleum oil and other hydrocarbons,
regardless of specific gravity, that are produced at the wellhead in
liquid form, except liquid hydrocarbons known as distillate or
condensate recovered or extracted from gas.
(49) “Oil or gas reservoir” means a natural underground oil
or gas bearing formation.
(50) “Open-flow test” means a measurement of the rate of flow
of a gas well when flowing into the air, unrestricted by any pressure
other than that of the atmosphere, and usually measured in thousands
of cubic feet (Mcf) per day.
(51) Operator.
(a) “Operator” means a person who, by virtue of
ownership, or under the authority of a lease or any other agreement,
has the right to drill, stimulate, complete, operate, maintain, or
control an oil or gas well or production facility.
(b) “Operator” includes:
(i) A person who holds a permit to drill or operator a
well;
(ii) A supplier; and
(iii) An owner.
(52) “Owner” means the person who has the right by deed,
lease, or otherwise to drill into and produce from a pool, or to store
in a pool, and appropriate the oil or gas the person produces or
stores either for the person or others.
(53) “Pay zone” means an oil or gas reservoir or portion of a
reservoir that contains economically producible hydrocarbons.
(54) “Perforating” means to make holes through the casing
opposite the producing zone to allow the oil or gas to flow into the
well.
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(55) “Permittee” means the person in whose name a seismic
permit or a drilling and operating permit has been issued.
(56) “Person” means the federal government, the State, a
county, municipal corporation, or other political subdivision of the
State, or their units, or an individual, receiver, trustee, guardian,
executor, administrator, fiduciary, or representative of any kind, or a
partnership, firm, association, public or private corporation, or any
other entity.
(57) “Pilot hole” means a vertical boring located from land
surface to the bottom of the targeted geologic formation to assist in
the identification of geologic features, underground voids, gas- or
water-bearing formations, geologic faults, and the lowest fresh water
aquifer.
(58) “Plug” means an expandable device or cement placed in a
well to prevent the movement of liquids and gas.
(59) “Pollutant” has the meaning stated in COMAR
26.08.01.01B(66).
(60) “Pool” means an underground oil or gas reservoir
containing a common accumulation of oil or gas, or both.
(61) “Pooled unit” means an area within which owners of
different properties in the area have voluntarily agreed to participate
in a well drilled within the unit.
(62) “Pressure maintenance” means the injection of liquid or
gas into an oil or gas reservoir to increase or maintain reservoir
pressure in order to recover additional quantities of hydrocarbons.
(63) “Produced water” means water that is produced from a
wellbore that is not flowback.
(64) “Producer” means the owner of a well capable of
producing oil, gas, or both.
(65) “Producing zone” means the stratum, bed, or formation
from which oil or gas enters the well.
(66) Production.
(a) “Production” means the act or process of producing oil
or gas from a natural oil or gas reservoir.
(b) “Production” does not include the sale or distribution of
oil or gas.
(67) “Production facility” means any equipment attendant to
oil and gas production including, but not limited to, tanks, flowlines,
headers, gathering lines, wellheads, heater treaters, pumps, valves,
compressors, injection equipment, and intrastate pipelines.
(68) “Proppant” means material inserted or injected into the
underground geologic formation that is intended to prevent fractures
from closing.
(69) “Ready-reserve” means the state of an engine that may
not be performing work at all times, but must be ready to take over
powering all or part of an operation at any time to ensure safe
operation of a process.
(70) “Recomplete a well” means to seal off one producing
zone, and perforate a new producing zone.
(71) “Reduced emission completion” has the meaning stated in
40 CFR § 60.5430.
(72) “Re-enter” means to drill out the plugs of an abandoned
well in a new effort to establish oil or gas production, or use the well
for another purpose.
(73) “Refracturing” means a subsequent high volume
hydraulic fracturing event following initial drilling and high volume
hydraulic fracturing to increase gas production.
(74) “Rework” means to perform remedial measures in a well
in order to restore oil or gas production that has declined
substantially or stopped completely.
(75) “Royalty interest” means the right to receive royalty
payments on the production of oil or gas.
(76) “Seismic operations” means the controlled application of
vibratory energy from any source to determine if favorable
conditions exist for the subsurface entrapment of oil or gas.
(77) “Seismic section” means a graphic, near-vertical display
of waveform data processed by a computer program to facilitate
interpretation of subsurface conditions.
(78) “Seismic survey” means a planned network or program of
seismic operations conducted by one person, one time, under one
permit.
(79) “Shotholes” means drilled holes which are subsequently
loaded with explosives whose detonation generates seismic waves
during a seismic survey.
(80) “Shut-in pressure” means the pressure in the well
measured at the wellhead in a specified period of time after the
valves are closed.
(81) “Special Conservation Areas” mean State-designated
Wildlands and areas identified by the Department of Natural
Resources as Irreplaceable Natural Areas.
(82) “Stimulate a zone” means to use techniques such as
hydraulic fracturing and acidizing in order to increase oil or gas
production from a formation.
(83) Stimulation Additive.
(a) “Stimulation additive” means a substance or
combination of substances added to a base fluid for purposes of
preparing well stimulation treatment fluid which includes, but is not
limited to, an acid stimulation treatment fluid or a hydraulic
fracturing fluid.
(b) “Stimulation additive” includes an additive that may:
(i) Serve additional purposes beyond the transmission of
hydraulic pressure to a geologic formation;
(ii) Be of any phase; and
(iii) Be a proppant.
(84) “Supplier” means an entity performing drilling or a well
stimulation treatment or an entity supplying an additive or proppant
directly to the operator for use in drilling or a well stimulation
treatment.
(85) “Surface casing” means the first casing set inside the
conductor pipe, which seals off any shallow aquifers and also serves
as a foundation for all subsequent drilling activity.
(86) “Surface impoundment” means a natural topographic
depression, man-made excavation, or diked area formed primarily of
earthen materials, although it may be lined with man-made
materials, that is not an injection well.
(87) “Tidal wetlands” has the meaning stated in COMAR
26.24.01.02B.
(88) “Volatile organic compound (VOC)” has the meaning
stated in COMAR 26.11.01B(53).
(89) “Waters of this State” has the meaning stated in
Environment Article, §9-101, Annotated Code of Maryland.
(90) Well Pad.
(a) “Well pad” means the area extending to the limit of
disturbance of the grading plan for a drilling site where a well is to
be drilled and where drill rigs, pumps, engines, generators, mixers
and similar equipment, fuel, pipes, and chemicals are located.
(b) “Well pad” does not include temporary worker housing
and employee parking lots unless equipment, fuel, or chemicals are
stored there.
(91) Well Stimulation Treatment Fluid.
(a) “Well stimulation treatment fluid” means a base fluid
mixed with physical and chemical additives, which may include acid,
for the purpose of a well stimulation treatment.
(b) “Well stimulation treatment fluid” includes hydraulic
fracturing fluids and acid stimulation treatment fluids.
(92) Wellhead Protection Area.
(a) “Wellhead protection area” means the surface and
subsurface area, determined by the Department under the
Department’s Water Supply Program, surrounding a water well or
well field that supplies a public water system, through which
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contaminants are reasonably likely to move toward and reach the
water well or well field; and
(b) “Wellhead protection area” means, for a public water
system that withdraws less than 10,000 gallons per day from
fractured rock aquifers and for which a wellhead protection area has
not been defined by the Department’s Water Supply Program, a fixed
radius of 1,000 feet around the one or more water wells.
(93) “Wildcat well” means an exploratory well drilled for oil
or gas on a geologic feature not yet proven to be productive, or in an
unproven territory, or to a zone that has never produced or is not
known to be productive in the general area.
(94) “Wildlands” means areas designated by the General
Assembly under Natural Resources Article, §5-1205, Annotated Code
of Maryland.
(95) Workover.
(a) “Workover” means the repair or stimulation of an
existing oil or gas production well for the purpose of restoring,
prolonging, or enhancing the production of hydrocarbons.
(b) “Workover” includes refracturing.
(96) “Zonal isolation” means the isolation through specified
cementing and casing practices of all fluid-bearing formations,
whether the fluids are gaseous or liquid, along the vertical borehole.
.02 Incorporation by Reference.
In this chapter, the following documents are incorporated by
reference:
A. Guidelines for Administering Oil and Gas Activity on State
Forest Lands (Pennsylvania Department of Conservation and
Natural Resources, Revised 2013);
B. Maryland Standards and Specifications for Soil Erosion and
Sediment Control, which has been incorporated by reference in
COMAR 26.17.01.11;
C. 40 CFR Part 86, as amended; and
D. 40 CFR § 60.5430, as amended.
.03 Responsibility for Compliance.
A. Where an obligation is imposed on an operator under this
chapter, the permittee is responsible for assuring that the obligation
is met.
B. If an obligation imposed on an operator under this chapter is
not met, the operator as well as the permittee shall be liable for the
noncompliance.
C. No indemnification, hold harmless, or similar agreement or
conveyance shall be effective to transfer from the permittee, to any
other person, the liability imposed under this chapter.
D. Nothing in this regulation shall bar any agreement to insure,
hold harmless, or indemnify a party to such agreement for any
liability under this chapter.
.04 Incident Notification.
A. In addition to any other notifications required by law or permit,
an operator shall report any condition such as fires, breaks,
blowouts, leaks, escapes, spills, overflows, or other occurrences at
the well pad, at pipelines and compressors, and during transport that
create a safety or pollution hazard immediately, but not later than 30
minutes after detection:
(1) To the emergency contact official of the nearest
downstream water supplier if pollutants are not contained on the well
pad; and
(2) To the Department.
B. The operator shall remain available until clearance to leave is
given by the Department.
.05 Seismic Permit Application Procedures.
A. A person may not conduct seismic operations in the State
without obtaining a seismic permit from the Department.
B. A seismic permit may not be transferred without written
permission of the Department.
C. Application Procedures for a Seismic Permit Applicant.
(1) A seismic permit application shall be:
(a) On a form provided by the Department; and
(b) Completed and signed by the seismic contractor or the
contractor’s authorized agent.
(2) The seismic permit application shall include:
(a) The name, address, and telephone number of the
applicant’s resident agent;
(b) U.S. Geological Survey 7.5-minute topographic maps,
hydrographic charts, or copies, showing the location of seismic lines;
(c) Certification that State and county permit and bond
requirements have been met for any seismic operations;
(d) A statement, on a form provided by the Department,
signed by each affected property owner providing the operator with
the right of entry to conduct seismic operations;
(e) Authorization, on a form provided by the Department,
signed by property owners who can grant legally binding rights of
entry to the property, authorizing representatives of the Department
and the Department of Natural Resources to enter their private
property for the purpose of inspecting seismic operations that are
ongoing or have been conducted on the property;
(f) A reclamation plan detailing how any area disturbed by
the seismic operation will be restored;
(g) A certificate of insurance for personal injury and
property damage liability coverage of not less than $1,000,000 for
each person injured and $5,000,000 for each occurrence or accident;
and
(h) A specific calendar schedule for the proposed operation
which prohibits any in-stream work during the spawning season of
anadromous fish and the spawning season for self-sustaining brook
trout populations.
(3) Applications for permits to conduct seismic operations on
the waters of Chesapeake Bay and its tidal tributaries shall be
accompanied by a written agreement to provide the Department with
processed seismic sections as soon as these sections are available,
but not more than 1 year after field operations are completed.
(4) The applicant shall provide additional information
considered necessary by the Department to process the permit.
D. A request for modification of the activities approved under the
seismic permit shall be submitted to the Department in writing, and
shall be approved by the Department before the person conducts the
modified seismic operation.
E. Application Processing Procedures for the Department.
(1) The Department shall review the application to determine
whether it is administratively complete.
(2) If the required information is not included, the Department
shall advise the applicant by written or oral communication that the
application is incomplete, and may suspend processing the permit
application pending receipt of deficiencies.
(3) The Department may deny a permit if the:
(a) Applicant does not submit the information required by
the Department;
(b) Proposed activity poses a substantial risk of causing
environmental damage that cannot be mitigated by the applicant such
as that set forth in Environment Article, §14-109(b)(6)(ii), Annotated
Code of Maryland; or
(c) Proposed operation will violate this chapter.
(4) If the Department’s decision is to deny the permit, a
notification of denial shall state the reasons for denial, modifications,
if any, necessary for approval of the application, and the hearing
rights as provided in Environment Article, §5-204, Annotated Code
of Maryland and State Government Article, Title 10, Subtitle 2,
Annotated Code of Maryland.
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(5) Information contained in the application and accompanying
documents and required reports shall be available to the public,
except for confidential geological and geophysical information
protected under General Provisions Article, §4-335, Annotated Code
of Maryland.
(6) The Department may include special provisions or modify
conditions in the permit for environmental, safety, or other relevant
reasons.
F. The seismic permit is valid for 12 months from the date of
issuance.
G. In addition to any other remedies provided by law, after notice
to the permittee and the opportunity for a hearing, the Department
may revoke a seismic permit for the reasons in Regulation .58 of this
chapter.
.06 Use of Explosives in Seismic Operations.
A. Persons using explosives in seismic operations shall comply
with all applicable local, State, and federal laws and regulations that
control the handling or detonation of explosive materials.
B. The use of explosives in seismic operations on or in the waters
of the Chesapeake Bay and its tributaries is prohibited.
C. Use of explosives shall be conducted by a person licensed to
handle explosives under the Public Safety Article, Title 11, Subtitle 1,
Annotated Code of Maryland.
D. The use of explosives shall be conducted in a manner not to
cause injury to persons, damage to public or private property,
adverse impacts on an underground mine, or to bring about any
change in the course, current, channel, or availability of ground
water or surface waters.
E. The use of explosive charges on elevated poles as an energy
source, referred to as the Poulter method, or with the charges laid on
the surface of the ground, is prohibited.
F. After explosives are loaded into shotholes, the explosives
handler shall keep the loaded holes under surveillance until the
charges are detonated.
G. Persons using explosives in seismic operations shall comply
with the following additional safety measures:
(1) Explosives in a shothole may not be detonated unless the
explosives handler determines that the area is clear and safe to
proceed;
(2) Explosives may not be left in a shothole overnight; and
(3) Seismic operations that use explosives shall be conducted
only during daylight hours, and the Department may impose a more
restrictive time period.
H. Persons using explosives in seismic operations are subject to
the following additional blasting restrictions:
(1) The operator shall obtain written approval from the
Department before blasting within 500 feet of any occupied dwelling,
commercial building, school, church, or hospital;
(2) The Department may require a seismographic record of any
blast; and
(3) The Department may prohibit blasting at specific times and
in specific areas, if necessary, to protect public safety, natural
resources, or the environment.
.07 Completion of Seismic Permit Operations.
Within 30 days after the completion of seismic work, the operator
shall;
A. Notify the Department of the status of the operation in writing;
B. Provide the Department with the results of the seismic survey,
which shall be considered public information except for confidential
geological and geophysical information protected under General
Provisions Article, §4-335, Annotated Code of Maryland; and
C. Complete reclamation work as required by the seismic permit.
.08 Drilling and Operating Permit Required.
A. A person proposing to conduct any of the following operations
to explore for, store, produce, or increase the production of oil or gas
within the State shall obtain a drilling and operating permit from the
Department before the person:
(1) Prepares a well site for the operation;
(2) Drills a well for oil or gas;
(3) Redrills at a location previously permitted;
(4) Re-enters a well;
(5) Deepens an existing well drilled for oil or gas;
(6) Drills a core hole or stratigraphic test; or
(7) Drills a well for the storage of natural gas or the
observation of the storage of natural gas.
B. An operator shall maintain a valid permit until the well is
abandoned in accordance with the approved plan for abandoning the
well.
.09 Prerequisite for Application for a Permit.
A. Except as provided in §B of this regulation, unless the new oil
or gas well is included in an approved CDP, a person may not
submit, and the Department may not accept or process, an
application for a drilling and operating permit for an oil or gas well
that will use one or more of the following techniques:
(1) Directional drilling;
(2) More than one well on a well pad;
(3) Acid stimulation, except for acid stimulation of a storage
well; and
(4) High volume hydraulic fracturing.
B. A person may apply for, and the Department may accept and
process, a drilling and operating permit to drill a wildcat well
without first obtaining approval of a Comprehensive Development
Plan in accordance with this chapter.
.10 Fees Associated with Seismic Permits and Drilling and
Operating Permits.
A. The fees imposed under this regulation shall be set by the
Department at the rate necessary to administer and implement
programs to oversee oil and gas exploration and production, storage
of oil and gas in depleted underground pools, and other requirements
related to the drilling of oil and gas wells, including all costs
incurred by the State to:
(1) Review, inspect, and evaluate monitoring data,
applications, licenses, permits, analyses, and reports;
(2) Perform and oversee assessments, investigations, and
research;
(3) Conduct permitting, inspection, and compliance activities;
and
(4) Develop, adopt, and implement regulations, programs, or
initiatives to address risks to public safety, human health, and the
environment related to the drilling and development of oil and gas
wells, including the method of hydraulic fracturing.
B. In any fiscal year, if the fee schedule established by the
Department generates revenue that exceeds or falls short of the
amount necessary to operate a regulatory program to oversee the
drilling of oil and gas wells, the Department shall adjust the fees in
the following fiscal year.
C. Until modified in accordance with §D of this regulation:
(1) An applicant for a seismic permit shall pay a fee of $5,000
to the Department upon submission to the Department of the
application for a seismic permit.
(2) An applicant for approval of a CDP shall pay a fee of
$30,000 to the Department upon submission to the Department of the
draft CDP for preliminary review.
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(3) An applicant for a drilling and operating permit shall pay a
fee for each well to the Department of:
(a) $30,000 with the application for drilling a new well or
reentering a well;
(b) $20,000 with the application for refracturing or
reworking a well; and
(c) $25,000 for the 5-year renewal of a drilling and
operating permit for an oil or gas well installed after October 1,
2010.
(4) A permittee who requests a modification or transfer of a
permit shall pay a fee of $1,000 to the Department.
D. The Department may administratively adjust its fees in
accordance with §B of this regulation by:
(1) Posting a proposed revised fee schedule on its website
along with justification for the proposed fee revision at least 30 days
before the new fee schedule is to take effect;
(2) Allowing public comment for 30 days after posting;
(3) Considering comments made during the public comment
period; and
(4) Posting the final fee revisions on its website.
E. Fees paid to the Department under this regulation are not
refundable.
.11 Comprehensive Development Plan—Purpose and Scope.
A. A CDP shall:
(1) Identify the locations for well pads, access roads, pipelines,
and other ancillary facilities to be developed, and include a plan for
transportation routes; and
(2) Assure that the locations of items identified in §A(1) of this
regulation and the plan for transportation routes:
(a) Avoid, to the extent possible, adverse site-specific and
cumulative impacts to public health, the environment, the economy,
and the people of Maryland;
(b) Minimize the adverse impacts that cannot be avoided;
and
(c) Mitigate the remaining impacts.
B. The CDP shall address as much as possible of a CDPapplicant’s planned development, but not less than the plans for the 5
years following submission of the CDP.
C. The geographic scope of the CDP shall include, at a minimum,
all land on or under which the applicant expects to conduct
exploration or production activities over a period of at least the
succeeding 5 years.
D. The CDP may be submitted by a single person or by more than
one person for an assemblage of land in which the persons hold
mineral rights.
E. An approved CDP will remain in effect for 10 years, but one
renewal for an additional 10 years may be granted by the
Department if the resource information is updated and the locations
approved in the initial CDP are not prohibited under any more
stringent location restrictions or setback requirements enacted after
the approval of the initial CDP.
.12
Procedure and Approval Process for Comprehensive
Development Plan.
A. If a CDP is a prerequisite for applying for a permit to drill a
well under Regulation .09 of this chapter, a person who seeks to
obtain a permit under the Environment Article, §14-104, Annotated
Code of Maryland, shall prepare a CDP that complies with location
and setback restrictions under Regulation .18 of this chapter and
avoids, minimizes, and mitigates adverse impacts to public health, the
environment, the economy, and the people of Maryland in
accordance with Regulation .11 of this chapter.
B. The CDP shall include:
(1) A map and accompanying narrative showing the proposed
location of all planned wells (vertical and horizontal portions), well
pads, gathering and transmission lines, compressor stations,
separator facilities, access roads, and other supporting
infrastructure;
(2) Survey data and field notes from a geological survey of the
area covered by the CDP; including, at a minimum:
(a) Locations of all gas and oil wells (abandoned and
existing), current water supply wells, and springs;
(b) Geologic map and cross section of the area;
(c) Fracture-trace mapping, orientation and location of all
joints, faults and fractures; and
(d) Other additional geologic information as required by the
Department;
(3) Identification of travel routes in Maryland for
transportation of equipment and materials to and from the well pad;
(4) A water acquisition plan that:
(a) Identifies the amount of water needed to support the
CDP;
(b) Identifies the sources of that water; and
(c) Includes, if a water appropriation permit will be needed,
a generalized water appropriation plan that identifies the proposed
locations and amounts of water withdrawals; and
(5) The sequence of well drilling over the lifetime of the plan
that places priority on locating the first well pads in areas removed
from sensitive natural resources.
C. The CDP shall be prepared using the State’s CDP planning
guide and the State-provided toolbox that includes geospatial data
necessary for adhering to location restrictions and setbacks and
addressing additional planning criteria. The CDP-applicant shall
also provide other information as needed, including a field
assessment for unmapped streams, wetlands, and other sensitive
areas.
D. Preliminary Review.
(1) The CDP-applicant shall submit a draft CDP, including
mapping information submitted as geospatial data following the
criteria specified in the CDP planning guide, to the Department.
(2) The Department shall forward the draft CDP for
preliminary review and comment by appropriate State and local
government agencies with responsibility for public health, natural
resources and roads.
(3) The Department shall send the preliminary comments to the
CDP-applicant within 45 days of receipt of the CDP by the
Department.
E. Submission of CDP.
(1) Following the CDP-applicant’s receipt and consideration
of the preliminary comments, the CDP-applicant shall submit the
CDP or a revised CDP to the Department for approval.
(2) Upon receipt of the CDP for approval, the Department will
initiate the following process for review and approval of the CDP:
(a) The Department will notify the Department of Natural
Resources, which shall convene a stakeholders group that includes a
representative of the CDP-applicant, appropriate State agencies,
local government,
resource managers, non-governmental
organizations, and surface owners;
(b) The expenses incurred by the Department of Natural
Resources in connection with the stakeholders group, up to an
amount agreed to with the Department, shall be reimbursed by the
Department from the Oil and Gas Fund;
(c) The stakeholders group will meet with the assistance of a
facilitator and, within 60 days after the Department’s receipt of the
CDP for approval, complete a discussion of how the CDP might be
improved;
(d) Following completion of the stakeholders group process,
the CDP-applicant may revise the CDP and will present it at a public
meeting in a county where land included in the CDP is located, and
the public shall be allowed to comment on the plan at the meeting or
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within 5 days after the meeting, after which the comment period
closes;
(e) Following closure of the comment period, the CDPapplicant may further modify the plan based on alternatives analyses
and public comment and shall submit the CDP to the Department of
Natural Resources; and
(f) The Department of Natural Resources shall, within 30
days of receipt of the CDP from the CDP-applicant, transmit the
CDP to the Department with written advice on whether the CDP:
(i) Conforms to location and setback requirements under
Regulation .18 of this chapter; and
(ii) To the maximum extent practicable, avoids adverse
impacts to public health, the environment, the economy, and the
people of Maryland, minimizes unavoidable impacts, and mitigates
remaining impacts.
F. Approval Process.
(1) Except as otherwise provided in this subsection, within 30
days after the Department of Natural Resources provides its written
advice to the Department, the Department shall, having considered
that advice, approve, disapprove, or partially approve and partially
disapprove the CDP.
(2) For good cause and after notice to the CDP-applicant, the
Department may extend the 30-day review period under §F(1) of this
regulation for an additional 30 days.
(3) If the Department disapproves, in whole or in part, a CDP,
the Department shall give the CDP-applicant a written notice of
disapproval that states the reasons for disapproval.
G. The disapproval, in whole or in part, of a CDP is subject to
judicial review as provided by Environment Article, §14-117,
Annotated Code of Maryland.
H. Modifications to the CDP.
(1) A significant modification to an approved CDP, such as a
change in the location of a drilling pad that places it closer to special
conservation areas, or the addition of new drilling pads, will require
the submission for approval of a modified CDP in accordance with
the procedures for review and approval of an initial CDP.
(2) A modification that causes no change in the surface impact
in the approved CDP, such as the installation of additional wells on
an existing pad or a change in the sequence of development, may be
approved by the Department upon request of the applicant without
the review process required for the initial CDP.
.13 Application for a Drilling and Operating Permit.
A. An application for a drilling and operating permit under
Regulation .08 of this chapter shall be submitted to the Department
on forms provided by the Department and shall contain the
following:
(1) The names, addresses, business status, and telephone
numbers of the applicant, operator, and resident agent;
(2) A plat prepared and certified by a Maryland licensed
professional land surveyor or property line surveyor containing the
information required in §C of this regulation;
(3) An environmental assessment, as required under Regulation
.17 of this chapter;
(4) Proof that the applicant meets the Financial Assurances
requirements of Regulation .53 of this chapter;
(5) A copy of the oil and gas lease that gives the operator the
right to enter and drill at the location shown on the plat and if the
mineral rights have been severed, a copy of the right of entry
agreement with the surface owner;
(6) If a pooled unit, copies of all leases in the unit which shall
accompany the application showing the right to pool interests;
(7) A copy of an agreement signed by the applicant and the
landowner stating that the Department and the Department of
Natural Resources may enter the land to inspect for compliance with
laws, regulations and permit conditions at any reasonable time
during the term of the permit and until the performance bond is
released;
(8) Certification and documentation by the applicant that the
applicant has notified, in writing, each landowner and leaseholder of
real property that borders or is within 2,640 feet of the boundary of
the proposed drillable lease area of the applicant’s intention to file
an application for a permit to drill a well;
(9) Written approval by the local zoning authority that all local
planning and zoning requirements have been met;
(10) A sediment and erosion control plan approved by the
Department, or the appropriate soil conservation district;
(11) A reclamation plan for restoring the well site;
(12) A spill prevention, control, and countermeasure plan;
(13) A statement listing all other federal, State, county, and
local permits and approvals required, and the status of each;
(14) The plan required under Regulation .21 of this chapter;
and
(15) Other relevant information and documents considered
necessary by the Department.
B. When an applicant seeks to directional drill, the applicant shall
state the:
(1) Reason for the proposed directional drilling;
(2) Depth at which deviation from the vertical is planned;
(3) Total depth of the vertical drill; and
(4) Horizontal distance and direction of the planned objective
with reference to the surface location.
C. Drilling and Operating Permit Plat.
(1) The plat or plats shall be submitted:
(a) On paper that is of appropriate quality and
dimensionally-stable at a scale of 1 inch equals 600 feet; and
(b) In a digital format approved by the Department.
(2) Information Required to be Included in Plat. The plat or
plats shall include the following information prepared by a Maryland
licensed professional land surveyor or property line surveyor:
(a) The proposed well location;
(b) If directional drilling is proposed, the locations of the
surface borehole, the proposed bottom-hole, and the lateral shall be
shown;
(c) At least two permanently established property tract
boundary corners, with bearings and distances to the proposed well
established by an on-ground survey;
(d) Boundaries of the lease or pooled unit containing the
well location, with individual lease boundaries within a pooled unit
being shown by an on-ground survey, deed calls, or tax map
references;
(e) Boundaries of adjoining properties with names and
addresses of fee owners, surface owners, mineral owners, and oil and
gas lessees; and
(f) The following information obtained from the best
available sources:
(i) Active oil and gas drilling, production wells,
abandoned wells, storage wells, and injection wells within 2,640 feet
of the proposed well location;
(ii) Water wells and springs within 2,640 feet of the
proposed well location;
(iii) Churches, schools, buildings, and occupied
dwellings within 2,640 feet of the proposed well location;
(iv) Any part of the Critical Area, 100-year floodplain as
established by the Federal Emergency Management Agency flood
insurance rate maps, nontidal wetlands, streams, or other bodies of
water within 1 mile of the proposed well;
(v) Roads, railroads, and other transportation routes
within 2,640 feet of the proposed well;
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(vi) Location of active and abandoned underground coal
mines and workings within 1 mile of the proposed well; and
(vii) A legend identifying the different types of wells and
other features shown on the plat.
(3) All plat lines actually surveyed shall be shown with solid
lines, and lines taken only from deed descriptions or tax maps shall
be shown by broken lines.
(4) Ownership and lease information may be based upon
current tax records or land record indexes.
(5) The applicant may supply ownership and lease information
on a supplemental list indexed to the tracts on the plat.
.14 Review Procedures for Drilling and Operating in the Critical
Area.
A. Following receipt of a permit application for a project located
in the Critical Area, the Department shall send a copy of the permit
application and all accompanying documents to the Critical Area
Commission for the Chesapeake and Atlantic Coastal Bays for review
and recommendations.
B. The Critical Area Commission for the Chesapeake and Atlantic
Coastal Bays shall submit written recommendations on the
application to the Department within 150 days of receipt of the
application and accompanying documents.
C. Following receipt of the recommendations by the Critical Area
Commission for the Chesapeake and Atlantic Coastal Bays on the
application, the Department shall adopt, to the maximum extent
permitted by law, permit conditions recommended by the Critical
Area Commission for the Chesapeake and Atlantic Coastal Bays.
.15 Drilling and Operating Requirements and Permit Conditions.
The Department may place in a drilling and operating permit
conditions which the Department deems reasonable and appropriate
to assure that the operation shall fully comply with the requirements
of Environment Article, Title 14, Subtitle 1, Annotated Code of
Maryland and this chapter, and provide for public safety and the
protection of the State’s natural resources.
.16 Departmental Review Procedures for Drilling and Operating
Permit.
A. Following receipt of a drilling and operating permit
application, the Department shall conduct a review to determine if
the application is administratively complete and notify the applicant
of deficiencies.
B. The Department may request additional information from the
applicant after the application is administratively complete.
C. When the Department determines that all necessary information
has been submitted in proper form, it shall notify the applicant that the
application is considered complete and provide for public participation
in the Department’s review by the following means:
(1) The Department shall publish notice of the application once per
week for 2 consecutive weeks in a newspaper of general circulation in the
county where the proposed permit activity would occur;
(2) The applicant shall pay all costs associated with publishing
notice of the application;
(3) The published notice of the application shall provide an
opportunity to request a public informational meeting on the
application;
(4) Following publication of the notice of the application, a
person interested in the pending application for a drilling and
operating permit may request that the Department schedule a public
informational meeting; and
(5) If the Department receives a request for an informational
meeting:
(a) The meeting shall be held within 45 calendar days of the
date of the request, unless extenuating circumstances justify an
extension of time; and
(b) The Department shall publish notice of the public
informational meeting once per week for 2 consecutive weeks in a
newspaper of general circulation in the county where the proposed
permit activity would occur.
D. The Department shall deny a drilling and operating permit if
the Department determines that the proposed activities pose a
substantial threat to public safety or a risk of significant adverse
environmental impact, particularly to:
(1) The Critical Area;
(2) Tidal or nontidal wetlands;
(3) Endangered or threatened species, or species in need of
conservation of their habitat;
(4) Historic properties as provided for in State Finance and
Procurement Article, §5A-326, Annotated Code of Maryland; or
(5) Populated areas.
E. The Department may issue a permit for directional drilling
when directional drilling is:
(1) Required for proper geologic evaluation; or
(2) Necessary to protect specific features, including:
(a) A water body;
(b) The Critical Area;
(c) A park;
(d) A building; or
(e) A highway, or other developed or natural features.
F. The Department’s decision to grant or deny a drilling and
operating permit may be issued not later than 30 calendar days after
the close of the record for the public informational meeting.
G. The Department shall mail or provide electronic written notice
of the decision to grant or deny the permit to:
(1) The applicant;
(2) Participants at a public informational meeting on the
application;
(3) Persons who comment on the application; and
(4) All landowners and owners of mineral, oil, and gas rights
within 1,000 feet of the proposed well.
.17 Environmental Assessment and Baseline Monitoring.
A. With the application for a drilling and operating permit to drill
a well, the applicant shall submit an environmental assessment and 2
years of baseline monitoring of the surface water, ground water, and
air in the vicinity of the well pad.
B. Baseline monitoring required under §A of this regulation shall
be completed before any site preparation or construction is begun at
the site of the planned well pad.
C. The Department, in consultation with the Department of
Natural Resources, shall develop guidance for the environmental
assessment and the baseline monitoring that will include sampling
design, monitoring protocols, quality assurance and quality control
criteria, and specifications for analysis and data submission.
D. The Department shall coordinate with the Department of
Natural Resources in its evaluation of the environmental assessment.
.18 Location Restrictions and Setbacks.
A. The Department may not issue a drilling and operating permit
for drilling in the waters or tributaries of the Chesapeake Bay.
B. The Department may not issue a drilling and operating permit
to drill in the Critical Area unless the applicant has obtained written
approval from the Critical Area Commission for the Chesapeake and
Atlantic Coastal Bays.
C. The Department may not issue a drilling and operating permit
for a well if any part of the land within the limit of disturbance of the
well pad is within 1,000 feet from the boundary of the property on
which the well is to be drilled.
D. The setback restrictions for well pads in §G of this regulation
also apply to all oil and gas development activities that result in
permanent surface alteration that would negatively impact aquatic
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habitat, special conservation areas, cultural and historical sites,
State and federal parks, forests and trails, wildlife management
areas, wild and scenic rivers, and scenic byways.
E. The Department may increase the setback distances in §G of
this regulation if necessary due to local topography, prevailing
winds, or other site-specific conditions.
F. If the pathway of a buried pipeline will be permanently
maintained in a vegetated state, the pipeline will not be considered to
result in permanent surface alteration.
G. The Department may not issue a drilling and operating permit
if any part of the land within the limit of disturbance for the well pad,
or other gas development activities that result in permanent surface
alteration, including permanent roads, compressor stations,
separator facilities, and other permanent infrastructure, is:
(1) On land with a slope, before grading, of greater than 15
percent;
(2) Within the watersheds of any of the following drinking
water reservoirs:
(a) Broadford Lake;
(b) Piney Reservoir; or
(c) Savage Reservoir;
(3) Within 450 feet from the edge of an aquatic habitat;
(4) Within 600 feet from special conservation areas;
(5) Within 300 feet from a cultural or historical site, State or
federal parks, trails, wildlife management areas, wild and scenic
rivers, and scenic byways;
(6) Within public lands owned or managed by the Department
of Natural Resources without the approval of the Department of
Natural Resources;
(7) Within 1,000 feet of known caves;
(8) Within 750 feet of the downdip side of a limestone outcrop;
(9) Within 1,000 feet from any occupied building, school or
church;
(10) Within 1,000 feet from the boundary of a wellhead
protection area;
(11) Within 2,000 feet from a private drinking water well; or
(12) Within an area defined as all lands at an elevation equal
to or greater than the discharge of a spring used as the source of
domestic drinking water by the resident(s) of the property on which
the spring is located, not to exceed 2,500 feet unless the Department
approves an alternative based on the delineation of recharge area of
the spring.
H. Unless the applicant provides evidence satisfactory to the
Department that its plan for well completions operations will control
pressure and fluid movement within the target geological formation
so these changes do not adversely interact with an abandoned oil or
gas well or other wells, the Department may not issue a permit to
drill a vertical or horizontal segment of well within 1,320 feet of an
abandoned oil or gas well or an active oil or gas well.
I. Except for wells with horizontal segments drilled from vertical
boreholes on a common well pad, the Department may not issue a
permit to drill and complete a gas well closer than 2,000 feet to an
existing gas well in the same oil or gas reservoir unless the
Department is provided with credible geologic evidence of reservoir
separation to warrant granting a spacing exception.
J. Except for wells with horizontal segments drilled from vertical
boreholes on a common well pad, the Department may not issue a
permit to drill and complete an oil well closer than 1,320 feet to an
existing oil well in the same oil or gas reservoir unless the
Department is provided with credible geologic evidence of reservoir
separation to warrant granting a spacing exception.
.19 Prohibited Acts.
A person may not operate a well in a way that results in physical
and preventable loss of oil and gas through inefficient or careless
operating practices, such as:
A. Operating or producing any oil or gas well in a manner that
would result in a reduction of the ultimate quantity of oil or gas to be
recovered from a pool;
B. Inefficient storing or improper handling of oil causing
excessive evaporative loss, spillage on the surface, or leakage into
the subsurface;
C. Producing oil or gas in a manner causing unnecessary water
channeling or coning;
D. Permitting gas produced from a gas well to escape into the air;
E. Flaring of gas from a well producing both oil and gas; or
F. Creating fire hazards.
.20 Wildcat Well.
A. A CDP is not a prerequisite for a permit to drill a wildcat well.
B. Except as provided in §A of this regulation, an application for a
wildcat well shall meet all other substantive and procedural
requirements for a drilling and operating permit, including
submission of the information required for a Completion Report
under Regulation .41 of this chapter.
C. A company may apply for permits for wildcat wells before
submitting a CDP for approval.
D. The wildcat well shall comply with all of the location
restrictions, setbacks, and other requirements for a drilling and
operating permit including two years of baseline monitoring and an
environmental assessment.
E. Once a permit for a wildcat well has been issued, no other well,
wildcat or production, may be permitted within a 2.5 mile radius
around the wildcat well until a CDP has been approved.
F. Unless the Department determines that the wildcat well can be
connected to a transmission line without any adverse impact on
wetlands, forest, or nearby residents, the exploratory well may not be
converted to a production well until a CDP for that area is approved.
.21 Performance Standards and Minimum Requirements.
A. In an application for a drilling and operating permit to drill a
well, the applicant shall submit a detailed plan for construction and
operation of the well that demonstrates that the planned activity
meets or exceeds the performance standards and minimum
requirements of Regulations .22 through .52 of this chapter.
B. In preparing the plan, the applicant shall consider industry
standards and practices as well as API standards.
C. The Department may require the applicant to use specified
technology for drilling, well stimulation, production and
abandonment if those methods have been demonstrated to have lower
potential adverse impacts and to be as effective as the applicant’s
proposed technology.
D. If the Department approves the plan, it shall be incorporated
by reference into the drilling and operating permit.
.22 Drilling.
A. The drilling liquid used shall be conditioned and tested daily to
assure it is capable of:
(1) Sealing off each oil, gas, brackish and salt water, or fresh
water zone to be encountered; and
(2) Exerting pressure in excess of those pressures anticipated
by the operator in any formation to be penetrated.
B. When air is permitted as the circulating medium, sufficient
liquid shall be available at the site at all times to kill any flow from
the well.
C. When actual drilling begins, the operator shall:
(1) Notify the Department at least 72 hours before beginning to
drill;
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(2) Collect samples of drill cuttings for the Department’s use as
directed in the drilling and operating permit;
(3) Conduct an electrical induction and gamma ray log to
determine depth of fresh water zones;
(4) Conduct any other logs required by the Department in the
permit; and
(5) Run and permanently cement a string of surface casing in
the hole to a depth which is at least 100 feet below the deepest known
strata bearing fresh water, or the deepest known workable coal,
whichever is deeper.
.23 Stormwater.
A. There may not be a discharge of stormwater from the pad as
long as any fuel or chemicals are present on the pad.
B. Stormwater collected from the pad may be used for hydraulic
fracturing but, prior to use, the stormwater shall be stored in tanks
and not in a surface impoundment.
C. During the production phase of the wells on a pad, unless fuel
or chemicals are present, the operator shall follow a stormwater
management plan for the pad area approved by the Department or
the authorized approval authority.
.24 Sediment and Erosion Control.
Sediment and erosion shall be controlled in accordance with State
law and the approved sediment control plan for all construction,
including the well pad, ponds, access roads, and pipelines.
.25 Well Pad.
A. There may not be a discharge of pollutants from the pad.
B. The pad shall be constructed with a liner and berms with a
hydraulic conductivity of 10-7 centimeter per second or less.
C. The pad shall be capable of containing, at a minimum, the
volume of the 25-year, 24-hour precipitation event.
D. The liner shall be protected from damage by decking or other
material.
E. The pad design shall allow for the transfer of stormwater and
other liquids that collect on the pad to storage tanks on the pad or to
trucks that can safely transport the liquid for proper disposal.
.26 Access Roads.
A. Access roads shall be constructed and operated to allow safe
passage of vehicles accessing the site and shall include stormwater
controls and control of dust and mud.
B. The design, construction, and maintenance of unpaved roads
shall be at least as protective of the environment as the standards in
Guidelines for Administering Oil and Gas Activity on State Forest
Lands.
.27 Freshwater Storage.
A. Only freshwater may be stored in a surface impoundment.
B. A surface impoundment shall:
(1) Have at least 2 feet of freeboard at all times;
(2) Be at least 1 foot above the ground water table;
(3) Be impermeable;
(4) Allow no liquid or solid discharge of any kind into the
waters of the State; and
(5) Provide for diverting surface runoff from surface
impoundments.
C. Dikes associated with surface impoundments shall be:
(1) Constructed of compacted material, free of trees and other
organic material, and essentially free of rocks or any other material
which could affect their structural integrity;
(2) Maintained with a slope that shall preserve their structural
integrity; and
(3) Constructed and maintained in accordance with the current
Maryland Standards and Specifications for Soil Erosion and
Sediment Control.
.28 Chemical Use, Storage and Handling.
A. Except in an emergency, only additives for drilling and well
stimulation that have been disclosed to the Department in advance
may be used.
B. Diesel fuel shall not be used in hydraulic fracturing.
C. All liquids, except fresh water, shall be stored in watertight,
closed tanks or containers with secondary containment capable of
holding the volume of the largest tank or container.
D. All non-liquid chemicals shall be stored safely and protected
from contact with precipitation or collected water.
E. If the tanks holding liquid have the potential to emit methane or
VOCs and are vented to the environment, they shall be equipped with
pollution control equipment to destroy or capture methane and
VOCs.
.29 Disclosure of Chemicals.
A. Applicants for drilling and operating permits to drill gas wells
shall provide the Department with the name, CAS number, and
concentration of every chemical constituent of every commercial
chemical product it intends to use on the site. Unless the applicant or
supplier attests that the information is a trade secret, this information
shall be public information.
B. Within 30 days after well completion, the operator shall
provide to the Department a list of all chemicals used in fracturing,
the weight of each used, and the concentration of the chemical in the
fracturing fluid. Unless the operator attests that the information is a
trade secret, this information shall be public information under
General Provisions Article, §4-335, Annotated Code of Maryland.
C. Within 30 days after well completion, the operator shall
provide to FracFocus a list of all chemicals used in fracturing, the
weight of each used, and the concentration of the chemical in the
fracturing fluid in accordance with FracFocus rules on reporting and
trade secrecy.
D. If a claim is made that the concentration of a chemical in either
a commercial chemical product or the fracturing fluid is a trade
secret, the operator shall attest to that fact and, in addition to
providing the complete list to the Department, provide a second list
that includes every chemical by name and CAS number, but does not
link the chemical to a specific commercial product or reveal the
concentration. This list shall be public information under General
Provisions Article, §4-335, Annotated Code of Maryland.
E. The Department may share trade secret information with other
State and federal agencies that agree to protect the confidentiality of
the information.
F. The operator shall provide the local emergency response
agency with:
(1) The list of chemicals developed under §B of this regulation;
(2) The second list, developed under §D of this regulation, in
the event trade secrecy is claimed; and
(3) A copy of the Safety Data for every commercial product
brought to the well site that contains a substance designated as
hazardous chemical by the federal Occupational Safety and Health
Administration.
G. Upon request, the operator shall provide the public with the
same information made available to the local emergency response
agency. The operator may satisfy this requirement by providing the
information to the Department in a format the Department specifies;
the Department will post the information on its website until the well
completion report is filed and shall maintain it in the Department’s
file on the well until the well is properly abandoned.
H. If a claim of trade secrecy is made, the operator shall provide
to the Department contact information, including the name of the
company, an authorized representative, and a telephone number
answered 24 hours per day, 7 days per week by a person with the
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ability and authority to provide the trade secret information in
accordance with this regulation.
I. Health Care Professionals Diagnosing or Treating a Patient.
(1) An operator shall give the trade secret information
immediately to a health care professional who states, orally or in
writing, that the health care professional needs the trade secret
information to diagnose or treat a patient.
(2) The disclosure may not be conditioned on or delayed for the
execution of a confidentiality agreement.
(3) The health care professional may share the information
with other persons only as medically necessary, including, but not
limited to, the patient, other health professionals involved in the
treatment of the patient, the patient’s family members if the patient is
unconscious, unable to make medical decisions, or is a minor, the
Centers for Disease Control and Prevention, and other government
public health agencies.
J. Public Health Professionals.
(1) Upon written request and statement of need for public
health purposes, the operator shall give the trade secret information
to any health professional, toxicologist, or epidemiologist who is
employed in the field of public health, including such persons
employed at academic institutions who conduct public health
research.
(2) The disclosure may be conditioned on the signing of a
confidentiality agreement before disclosure.
(3) The recipient may share the information as professionally
necessary.
.30 Radioactive Sealed Sources and Other Radioactive Materials.
A. An operator shall comply with all applicable provisions of the
Maryland Radiation Act, Environment Article, Title 8, Annotated
Code of Maryland, and regulations promulgated under that title.
B. An operator shall disclose to the Department, before use, a
radioactive material in charges used to perforate casing, cement, or
both, and shall present a plan for safe handling, monitoring, and
disposal for approval by the Department.
.31 Transportation and Truck Traffic.
A. Travel for all heavy truck traffic to or from the well pad or to or
from centralized facilities serving the well pad shall be planned and
implemented to minimize conflicts with the public. The plan at a
minimum, shall:
(1) Avoid truck traffic during times of school bus transport of
children to and from school locations;
(2) Ensure that truck traffic does not interfere with public
events or festivals;
(3) Minimize truck traffic in residential areas; and
(4) Minimize conflict with public uses such as hunting and
fishing.
B. The number of truck trips to deliver material to the well pad
and remove wastes and the impact of the remaining trips shall be
reduced by one or more of the following methods, if they are
practicable for the specific site:
(1) Establishing a centralized water storage facility at a
location that minimizes the use of roads near homes or other
occupied buildings for the truck transportation of water to the
centralized water storage facility;
(2) Improving the roads to be used so that damage to the
roadways is minimized;
(3) Transferring water from the centralized storage facility to
the well pad using aboveground temporary hoses or pipes;
(4) If it is proven to be safe and effective and to have less
impact, establishing a centralized facility with all the equipment
necessary for preparing and pressurizing the fracturing fluid in a
location, with noise and air pollution controls that minimize impacts
to people, and deliver the water, proppant, and additives to the well
pad using pipes;
(5) If they are proven to be safe and effective and to have less
impact, performing fracturing using alternatives to high volume
water-based fracturing fluid; and
(6) Implementing other modifications proposed by the
applicant which are accepted by the Department as traffic reduction
measures.
.32 Protection of Sensitive Aquatic Resources During Water
Withdrawals.
A. If feasible, operators shall arrange to acquire water for drilling
and hydraulic fracturing from one or more permanent or semipermanent water supply access points with large capacity and
storage options to decrease risks related to water withdrawals such
as invasive species.
B. Applicants seeking water appropriation permits for water from
sensitive headwater streams and Use III and Tier II waters may be
required to perform additional studies, at the direction of the
Department in consultation with the Department of Natural
Resources, to ensure water withdrawals will not negatively impact
aquatic life.
.33 Protection of Fresh Water Aquifers.
A. The operator shall protect fresh water aquifers from
contamination during drilling and during the life of the well.
B. The drilling fluid used to drill intervals prior to reaching the
depth 100 feet below the deepest known stratum bearing fresh water,
or the deepest known workable coal, whichever is deeper:
(1) Shall be air, fresh water, a freshwater based drilling fluid,
or a combination of these; and
(2) May contain only additives that the manufacturer warrants
have been certified under NSF/ANSI Standard 60, Certification for
Drinking Water Treatment Chemicals – Health Effects.
.34 Control and Reporting of Air Emissions.
A. Reduced emissions completion shall be achieved on all oil and
gas wells that are subjected to high volume hydraulic fracturing or
re-fracturing.
B. The operator shall use top-down best available technology, as
determined by the Department and included as a condition of the
drilling and operating permit, for the control of air emissions,
including, to the extent relevant to the operations:
(1) Improved Compressor Maintenance to reduce emissions
from reciprocating compressors;
(2) Low-Bleed or No-Bleed Pneumatic Controllers used to
reduce emissions from control devices;
(3) Dry Seal Systems to reduce emissions from centrifugal
compressor seals;
(4) Rigorous Leak Detection and Repair (LDAR) program;
(5) Zero emission or dessicant well gas dehydration;
(6) Vapor Recovery Units used to reduce emissions from
storage tanks;
(7) Pipeline inspection, maintenance, and repair program; and
(8) Plunger lift systems when natural gas liquids (NGLs) are
present.
C. Methane Offset.
(1) Each calendar year the operator shall estimate the methane
emissions from each well pad including the emissions from the well
or wells on the pad and any other equipment on the pad.
(2) If feasible, the operator shall verify the estimates by
operational data and from the leak detection and repair program.
(3) By April 1 of each year, the operator shall report the
methane emissions for the previous calendar year, converted to CO2
equivalent emissions, to the Department.
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(4) Upon notification from the Department that CO2 equivalent
allowances are available, the permittee shall purchase sufficient
allowances to offset its methane emissions and provide
documentation to the Department of the purchase.
.35 Engines and Compressors.
The operator shall ensure that:
A. All on-road and non-road vehicles and equipment using diesel
fuel use Ultra-Low Sulfur Diesel fuel (maximum sulfur content of 15
ppm);
B. All on-road vehicles and equipment limit unnecessary idling to
5 minutes;
C. All trucks used to transport fresh water or wastewater meet
EPA Heavy Duty Engine Standards for 2004 to 2006 engine model
years in 40 CFR Part 86, as amended, which include a combined
NOx and non-methane hydrocarbon (NMHC) emission standard of
2.5 grams per brake horsepower-hour (g/bhp-hr); and
D. Except for engines necessarily kept in ready-reserve, all diesel
non-road engines limit idling to 5 consecutive minutes.
.36 Blowout Prevention.
A. The well shall be equipped with blowout prevention equipment
with two or more redundant mechanisms.
B. Blowout preventers shall be tested at a pressure at least 1.2
times the highest pressure expected to be experienced during the life
of the well; if this highest pressure occurs during well stimulation, it
shall be tested at a pressure at least 1.2 times higher than that
experienced during well stimulation.
C. The blow out preventer shall be tested on a weekly basis.
.37 Leak Detection and Repair (LDAR).
A. The applicant for a drilling and operating permit shall submit
to the Department for approval a written plan for methane leak
detection and repair.
B. The plan shall address:
(1) Training;
(2) LDAR audits;
(3) Contractor accountability;
(4) Internal leak definition for valves and pumps;
(5) More frequent monitoring;
(6) Repairing leaking components;
(7) Delay of repair compliance assurance;
(8) Electronic monitoring and storage of LDAR data;
(9) Quality assurance/quality control of LDAR data;
(10) Calibration/calibration drift assessment; and
(11) Records maintenance.
C. The plan shall address leak detection and repair from wellhead
to transmission line and assure prompt repair of leaks.
D. Records of leak detection and repair shall be made available to
the Department upon request.
.38 Well Construction, Casing, and Cement.
A. Wells shall be drilled, cased, and cemented to effectively isolate
the borehole from the surrounding formations and prevent the
migration of gas or liquids into or out of the casing and the
formations.
B. Pilot Hole.
(1) The operator shall drill at least one pilot hole from a well
pad before drilling any well from that pad that will include
directional drilling.
(2) The pilot hole shall extend from the surface of the ground to
the bottom of the targeted geologic formation.
(3) The operator shall perform open hole logging on the pilot
well to determine the geologic and hydrogeologic nature of the well
pad site and to assist in the identification of geologic features,
underground voids, gas- or water-bearing formations, geologic
faults, and the lowest fresh water aquifer.
(4) The operator shall submit the results of tests run on the
pilot hole, including the open hole logging data, to the Department
within 30 days after completing the pilot hole.
C. The applicant for a drilling and operating permit shall submit a
plan for the Department’s approval that describes, at a minimum,
how:
(1) A stable borehole will be drilled with minimal rugosity
(roughness of the borehole wall);
(2) Complete removal of drilling fluid will be accomplished;
(3) The cement system design addresses challenges to zonal
isolation;
(4) Other factors that could interfere with the proper placement
of the cement around the casing will be addressed; and
(5) The casing and cement will assure integrity throughout the
life of the well.
D. Adherence to the drilling, casing and cementing plan, as well
as integrity testing shall be a condition of the permit.
E. Unless the applicant submits proof that demonstrates to the
satisfaction of the Department that the applicant’s plan assures
isolation of the borehole from the surrounding formations and
prevents the migration of gas or liquid into or out of the casing and
the formation, as well or better than the minimum standards and
criteria established in this section, the plan shall meet the following
minimum standards and criteria:
(1) The conductor casing shall be cemented to the surface;
(2) The surface casing shall extend from the surface to at least
100 feet below the lowest fresh water and be cemented along its
entire length;
(3) The intermediate casing shall be installed and cemented
from its greatest depth to the bottom of the surface casing;
(4) Production casing shall be cemented along the horizontal
portion of the well bore and to at least 500 feet above the highest
formation where hydraulic fracturing will be performed, or to the
base of the intermediate casing, whichever is shallower;
(5) A representative sample of each cement formulation shall
be tested before use under conditions that are similar to those found
in the well where the cement will be used;
(6) Open hole logging shall be performed and used to optimize
the design and installation of the well;
(7) All casing installed in a well shall be steel alloy casing and
have a minimum internal yield pressure rating designed to withstand
at least 1.2 times the maximum pressure to which the casing may be
subjected during drilling, production, or stimulation operations;
(8) The minimum internal yield pressure rating shall be based
upon engineering calculations that shall be included in the plan;
(9) Thread and coupling designs for casing and tubing shall
meet or exceed the maximum anticipated tensile, compressive, burst,
and bending stress conditions for the well;
(10) Casing strings with threads should be assembled to the
correct torque specifications to ensure leak-proof connections;
(11) An operator shall use a sufficient number of centralizers to
properly center the casing in each borehole; and
(12) The cement shall be allowed to set at static balance or
under pressure for a minimum of 12 hours and shall have reached a
compressive strength of at least 500 psi before drilling the plug, or
initiating any integrity testing.
F. Reconditioned casing may be permanently set in a well only
after it has passed a hydrostatic pressure test with an applied
pressure at least 1.2 times the maximum internal pressure to which
the casing may be subjected, based upon known or anticipated
subsurface pressure, or pressure that may be applied during
stimulation, whichever is greater, and assuming no external pressure.
The casing shall be marked to verify the test status. All hydrostatic
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pressure tests shall be conducted by a method approved by the
Department. The owner shall provide a copy of the test results to the
Department before the casing is installed in the well.
.39 Integrity Testing.
A. Integrity testing is required to ensure proper cementing of the
well casing to the geological formations.
B. An applicant for a drilling and operating permit shall provide a
plan for integrity and pressure testing of the cased hole for approval
by the Department.
C. Segmented radial cement bond logging (SRCBL) shall be used,
supplemented by other methods that the Department may require in a
permit, such as omnidirectional cement bond logging and neutron
logging.
D. Before commencing hydraulic fracturing, the operator shall
certify to the Department the integrity of the casing and cement, the
isolation of all fluid-bearing (gas or liquid) formations, and the
sufficiency of the zonal isolation with supporting data.
E. If there is evidence of inadequate casing integrity or cement
integrity, the operator shall notify the Department and propose
remedial action.
F. Integrity testing shall be performed periodically during the
lifetime of the well using the tests and at the frequency specified by
the Department in the permit.
G. An additional integrity testing will be required before a well is
re-fractured.
H. All integrity test results shall be reported to the Department.
.40 Monitoring During Drilling and High Volume Hydraulic
Fracturing.
A. The operator shall perform a tiltmeter or microseismic survey
for the first well hydraulically fractured on each pad to provide
information on the extent, geometry, and location of fracturing.
B. The Department may require that tiltmeter or microseismic
surveys also be conducted for second and subsequent wells on a pad.
C. The operator shall provide the results of the tiltmeter or
microseismic survey, with an accompanying narrative, to the
Department with the Completion Report required by Regulation .41
of this chapter.
D. The operator shall maintain, at the site, a written record of:
(1) Each pressure test, integrity test, and mechanical test of:
(a) Casings;
(b) Blowout preventers;
(c) Surface connections;
(d) Fittings; and
(e) Auxiliary wellhead equipment; and
(2) Daily record of:
(a) Footage drilled;
(b) Hole size;
(c) Accidents; and
(d) Spills.
.41 Completion Report.
A. Within 30 days after the drilling, stimulating, and testing of a
well are completed, a completion report of the well shall be submitted
to the Department.
B. Except as provided in Regulation .29 of this chapter and for
confidential geological and geophysical information protected under
General Provisions Article, §4-335, Annotated Code of Maryland,
information contained in the completion report and accompanying
documents shall be available to the public.
C. The completion report shall be on a form furnished by the
Department and shall include:
(1) Depth at which any fresh water inflow was encountered;
(2) Lithology of penetrated strata, including color;
(3) Total depth of the well;
(4) A record of all commercial and noncommercial oil and gas
encountered, including depths, tests, and measurements;
(5) A record of all brackish and salt water inflows;
(6) A record of all casing used, including:
(a) Size, weight, amount, and depth set;
(b) Amount of cement used on each casing string; and
(c) Amount of casing recovered from the hole if the well was
abandoned;
(7) Generalized core descriptions, including:
(a) The type and depth of sample;
(b) Indications of oil, water, or gas;
(c) Estimates of porosity and permeability; and
(d) Percent recovery.
(8) Data recorded regarding perforating, stimulating, and
testing, including open-flow tests and shut-in pressures;
(9) Data on bridge plugs set, make and type of plug, depth plug
was set, whether plug was left in place or removed, and details of the
plug-back operation below the bridge;
(10) Information regarding the constituents of the fracturing
fluid required by Regulation .29 of this chapter;
(11) A copy of all electric, radiation, sonic, caliper, directional,
and any other type of logs run in the well; and
(12) The date on which verbal approval was obtained from the
Department to plug the hole as a dry hole in a continuous
progression from drilling or reworking.
.42 Site Security.
A. The operator shall secure the site.
B. At a minimum, security shall include:
(1) Perimeter fencing;
(2) Providing local emergency responders with duplicate keys
to locks;
(3) Fencing around any surface impoundments; and
(4) Posting appropriate signage that:
(a) Has letters at least 1 inch high;
(b) Indicates the name of the permittee, the name of the
lessor or landowner, and the Department and American Petroleum
Institute well identification numbers;
(c) Indicates phone numbers for the operator and regulatory
agencies required to be contacted in the event of an emergency at the
site;
(d) Is posted in a prominent place as directed by the
Department; and
(e) Is kept in good condition.
.43 Management of Drilling Fluids, Stimulation Fluids and
Produced Water.
A. All drilling fluids and cuttings shall be managed on the well
pad in a closed loop system without the use of a surface impoundment
for mud or cuttings.
B. Flowback and produced water shall be managed in a closed
loop system of tanks or containers at the pad site.
C. Flowback and produced water shall be recycled to the
maximum extent practicable. Unless the applicant demonstrates that
it is not practicable, the permit shall require that not less than 90
percent of the flowback and produced water be recycled, and that the
recycling be performed on the pad site of generation.
.44 Gathering Lines and Pipelines.
A. All necessary approvals and permits, including sediment and
erosion control, permits or licenses for dredging and filling of
wetlands, and stream crossing, shall be obtained prior to
construction.
B. Gathering lines shall be properly constructed, installed, and
operated to prevent any leaks.
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C. The person that owns or operates an underground facility for
the conveyance of oil or gas shall participate as an “owner-member”
in the “one-call system” as those terms are defined in the Maryland
Public Utilities Code, §12-101, Annotated Code of Maryland.
D. All pipelines and fittings appurtenant thereto used in the
drilling, operating, or producing of an oil well, a gas well, or both,
shall be designed for at least the greatest anticipated operating
pressure or the maximum regulated relief pressure in accordance
with the current recognized design practices of the industry.
.45 Flaring.
A. Flaring shall be allowed only if the content of flammable gas is
too low to sustain combustion, or when flaring is required for safety.
B. The following circumstances shall not justify flaring:
(1) Inadequate water disposal capacity;
(2) Undersized flowback equipment; or
(3) Except for wildcat wells, lack of a pipeline connection.
C. When flaring is permitted during well completion, recompletions, or workovers of any well, the operator shall adhere to
the following requirements:
(1) The operator shall either use a raised/elevated flare or an
engineered combustion device with a reliable continuous ignition
source, which has at least a 98 percent destruction efficiency of
methane.
(2) No impoundment flaring is permitted.
(3) Flaring may not be used for more than 30 days on any
wildcat well, unless the operator submits proof in a form acceptable
to the Department that an extension of time is necessary.
(4) Flares shall be designed for and operated with no visible
emissions, except for periods not to exceed a total of five minutes
during any two consecutive hours.
.46 Noise.
A. Noise shall be reduced to the lowest practicable level.
B. An applicant for a drilling and operating permit shall provide
to the Department a power plan that results in the lowest practicable
noise impact from the choice of energy source, including
consideration of the impact of noise from on-site generators.
C. Appropriate noise reduction devices shall be used and
maintained on all equipment at the pad site.
D. Noise modeling shall be conducted prior to beginning
operations to demonstrate that noise standards will be met and noise
sensitive areas will be protected.
E. The operator shall conduct noise monitoring at least once
during drilling and once during hydraulic fracturing, to confirm that
noise standards are met.
F. The Department may require the operator to perform noise
monitoring in response to complaints about noise.
.47 Lighting.
A. Night lighting:
(1) May be used only when and where necessary;
(2) Shall be directed downward; and
(3) Shall use low pressure sodium light sources wherever
possible.
B. If drill pads are located within 1,000 feet of aquatic habitat,
screens or restrictions on the hours of operation may be required to
reduce light pollution.
C. Light restrictions and management protocols shall minimize
conflicts with recreational activities, in addition to minimizing stress
and disturbance to sensitive aquatic and terrestrial communities
.48 Spill Prevention, Control and Countermeasures and Emergency
Response Plan.
A. All spills shall be entered in the record required in Regulation
.40D of this chapter.
B. In addition to any other notifications required by law or permit,
an operator shall report to the Department immediately, but not later
than 2 hours after detection, all spills and releases that are not
contained on the well pad.
C. All spills and releases shall be immediately cleaned up and the
waste properly disposed .
D. Each applicant for a drilling and operating permit shall
prepare and submit to the Department for approval a site-specific
emergency response plan for preventing the spills of oil and
hazardous substances and addressing spills that occur.
E. Before preparing the plan, the operator shall:
(1) Consult with the governing body of the local jurisdiction in
which the well is located to verify that local responders have
appropriate equipment and training to respond to an emergency at a
well;
(2) Identify the nearest downstream water system with a
surface intake, the estimated time of travel of a spill from the well site
to the intake of that downstream system under low, median and high
flow conditions, the emergency contact information of the nearest
downstream water supplier; and
(3) notify the nearest downstream water supplier regarding the
location of the planned drilling by certified mail, return receipt
requested.
F. The plan shall include, at a minimum:
(1) Using drip pans and secondary containment structures to
contain spills;
(2) Conducting periodic inspections;
(3) Using signs and labels;
(4) Having appropriate personal protective equipment and
appropriate spill response equipment at the facility;
(5) Training employees and contractors;
(6) Establishing a communication plan for providing
notification, information and updates about spills and other incidents
that:
(a) Contains contact names and telephone numbers; and
(b) Describes the process for informing:
(i) The public;
(ii) Local government;
(iii) Downstream water systems;
(iv) The Department; and
(v) The media; and
G. The operator shall have at least two vacuum trucks on standby
at the site during drilling, fracturing, and flowback so that any spills
occurring during those stages, which could be of significant volume,
could be promptly removed from the pad.
H. The operator shall identify specially trained and equipped
personnel who will respond to a well blowout, fire, or other incident
that personnel at the site cannot manage. These specially trained and
equipped personnel shall be capable of arriving at the site within 24
hours of the incident.
.49 Ongoing Monitoring and Corrective Measures.
A. If there is evidence of inadequate casing or cement integrity or
methane migration, the operator shall notify the Department
immediately and propose remedial action.
B. The operator shall monitor in accordance with the
Department’s standard protocols for environmental assessment
monitoring, recordkeeping, and reporting during drilling, hydraulic
fracturing, and production, as specified in the drilling and operating
permit.
C. The Department and the Department of Natural Resources
shall jointly develop standard protocols for ongoing monitoring and
assessment for air and water quality, terrestrial and aquatic living
resources, invasive species, geophysical assessments, and such
additional information as may be required by the Department.
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D. All information collected at the site and within the study area
shall be reported according to the protocols.
E. The Department may require more extensive testing of air,
surface water, and ground water in instances where elevated levels of
pollutants are suspected or have been detected.
.50 Invasive Species.
A. The applicant shall submit a plan with every drilling and
operating permit application for preventing the introduction of
invasive species (plants and animals) and controlling any invasive
species that is introduced.
B. The invasive species management plan required under §A of
this regulation shall emphasize avoidance, early detection, and rapid
response.
C. The plan required under §A of this regulation shall include, at
a minimum:
(1) Flora and fauna inventory surveys of sites prior to
operations, including water withdrawal sites;
(2) Procedures for avoiding the transfer of species by clothing,
boots, vehicles, and water transfers, including assuring that the water
withdrawal equipment is free from invasive species before use and
before it is removed from the withdrawal site;
(3) Interim reclamation following construction and drilling to
reduce opportunities for invasion;
(4) Annual monitoring and treatment of new invasive species
populations as long as the well is active; and
(5) Post-activity restoration to pre-activity community structure
and composition using seed that is certified free of noxious weeds.
D. Invasive species monitoring will be required at the appropriate
times of the year to identify early infestations.
.51 Site Reclamation.
A. The operator shall provide the Department with predevelopment and post-development photographic documentation to
ensure site closure conditions are satisfied.
B. The operator shall reclaim the site in two stages:
(1) Interim reclamation following well completion to stabilize
the ground and reduce opportunities for invasive species; and
(2) Final restoration using species native to the geographic
range and seed that is certified free of noxious weeds.
C. Reclamation shall address all disturbed land, including the
pad, access roads, ponds, pipelines, and locations of ancillary
equipment.
D. Drilling and Operating Reclamation Plan.
(1) The reclamation plan shall describe how roads, well sites,
and impoundments will be reclaimed.
(2) The reclamation plan shall include a:
(a) Proposed time schedule for each major step in the
reclamation plan;
(b) Description of measures to be employed to dispose of
debris, acid-forming and toxic-forming materials, and materials
constituting a fire hazard, and a description of the contingency plans
which have been developed to preclude sustained combustion of these
materials;
(c) Plan for backfilling, soil stabilization, compacting,
grading, and controlling surface drainage following regrading, with
contour maps at a scale of 1 inch equals 50 feet and cross sections
that show the existing slope and the anticipated final surface
configuration of the proposed permit area;
(d) Plan for removal, storage, and redistribution of topsoil,
subsoil, or other materials, and revegetation to protect the site from
erosion;
(e) Description, including appropriate cross sections and
maps, of the measures to be used to plug, case, or manage wildcat
wells, other wells, and other openings within the proposed permit
area;
(f) Description of how contaminated materials will be
disposed of in accordance with requirements of the Department;
(g) Plan for disposing of the cuttings by:
(i) Transporting to an approved disposal facility; or
(ii) Other methods of disposal as approved by the
Department; and
(h) Plan for removing and reclaiming the fresh water
surface impoundment.
.52 Wastes and Wastewater.
A. Wastes and wastewater shall be handled in accordance with
applicable federal, State, and local laws and regulations and
managed in a way that prevents pollution of the environment.
B. No drilling fluids, hydraulic fracturing fluid, flowback,
produced water or other wastewater associated the exploration,
development, or production of crude oil or natural gas may be
delivered to a wastewater treatment facility that discharges to waters
of this State unless the discharge permit for the wastewater treatment
facility specifically allows it to accept that wastewater.
C. No flowback or produced brine may be applied to land or used
for de-icing.
D. An operator shall keep a record of the volumes of wastes and
wastewater generated on-site, the amount treated or recycled on-site,
a record of each shipment off-site, and a confirmation that the
amount of waste shipped was received at the designated facility.
E. All trucks, tankers, and dump trucks transporting liquid or solid
wastes shall be fitted with GPS systems to track and record their
travel routes and travel time.
F. Cuttings, drilling mud, flowback, produced water, residue from
treatment of flowback and produced water, and any equipment where
scaling is likely to occur or sludge is likely to collect shall be tested
for radioactivity and disposed of in accordance with federal, State,
and local laws and regulations.
G. If cuttings show no level of radioactivity beyond background,
and meet other criteria established by the Department, including
sulfates and salinity, the Department may permit on-site disposal of
cuttings.
H. Records regarding wastes and waste shipments shall be
maintained for a period of three years and shall be delivered to the
Department upon request.
.53 Financial Assurances and Financial Test.
A. The applicant for a drilling and operating permit shall submit
to the Department proof of financial assurance by satisfying the
requirements of §B, §C, or §F of this regulation.
B. Unless the applicant submits proof in a form acceptable to the
Department that the applicant meets the financial test under §C of
this regulation, the applicant shall provide:
(1) A certificate of liability insurance showing personal injury
and property damage liability coverage of at least $1,000,000 for
each person and $5,000,000 for each occurrence or accident;
(2) A certificate of environmental pollution liability insurance
in an amount not less than $10,000,000 per loss for bodily injury and
property damage to persons and for natural resource damage,
including the costs of cleanup and remediation, caused by the sudden
or nonsudden release of pollutants, including the costs and expenses
incurred in the investigation, defense, or settlement of claims; and
(3) A performance bond, a blanket bond, cash, a certificate of
deposit, or a letter of credit, satisfactory to the Department, of at
least $50,000 for each gas or oil well, including each well on a
multiwell pad, but not less than the most recent closure cost estimate
provided by the operator under the Environment Article, §14-105(a),
Annotated Code of Maryland.
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C. An applicant may satisfy the financial assurance requirements
of this regulation by demonstrating that the applicant:
(1) Has been in continuous operation as a business entity for
not less than the 5 years immediately preceding the application;
(2) Has net working capital and tangible net worth of at least
$30,000,000;
(3) Has assets located in the United States amounting to at
least 90 percent of total assets or current assets of at least
$30,000,000; and
(4) Satisfies the criteria of either Test 1 as set forth in §D of
this regulation or Test 2 as set forth in §E of this regulation:
D. To satisfy Test 1, the applicant shall demonstrate, based on
current audited financial statements, that the applicant meets at least
two of the following three ratios:
(1) A ratio of total liabilities to net worth less than 2.0;
(2) A ratio of the sum of net income plus depreciation,
depletion, and amortization to total liabilities greater than 0.1;
(3) A ratio of current assets to current liabilities greater than
1.5.
E. To satisfy Test 2, the applicant shall demonstrate, based on
current audit financial statements, that the applicant has a current
rating for his most recent bond issuance of AAA, AA, A, or BBB as
issued by Standard & Poor’s Ratings Services or Aaa, Aa, A, or Baa
as issued by Moody’s Investors Services.
F. Gas Wells in Existence Before October 1, 2013.
(1) Except as provided in §F(2) of this regulation, a permittee
for drilling and operating a gas well that was in existence on or
before October 1, 2013, shall provide financial assurance by
maintaining the same performance bond and liability insurance that
is required for the holder’s most recent permit or permit renewal
issued on or before October 1, 2013.
(2) If a gas or oil well that was in existence on or before
October 1, 2013, is modified after October 1, 2013, by recompletion,
stimulation, deepening, or adding lateral extensions, the permittee
shall comply with the requirements for financial assurance contained
in §A of this regulation.
.54 Oil and Gas Correlative Rights.
A. Unless the drilling and operating permit provides for controlled
directional drilling or estimated natural deviation, a well may not
vary more than 3 degrees from the vertical.
B. If an operator needs to deviate more than 3 degrees from the
vertical, the operator shall notify the Department. Deviations larger
than 3 degrees from vertical may be permitted by the Department in
order to straighten the hole, sidetrack impenetrables, or to correct
other mechanical difficulties, if correlative rights are not in dispute.
C. The Department may require the deviation to be less than 3
degrees to protect correlative rights.
D. The Department shall have the right to require the operator to
run a complete angular deviation and directional survey by a
company knowledgeable about downhole surveys in directionally
drilled wells at the operator’s sole cost and risk.
E. If an angular deviation and directional survey verifies
violations of the approved well location or spacing requirements, the
Department may require the well to be redrilled or plugged and
abandoned.
.55 Requirements for Plugging and Abandonment of Oil or Gas
Wells.
A. An operator shall plug and abandon a well in accordance with
this regulation.
B. Upon the abandonment or ending of operation of any dry hole,
gas or oil well, storage well, pressure maintenance well, or
stratigraphic well, the operator shall plug the hole in compliance
with the plan approved by the Department.
C. The operator shall notify the Department at least 72 hours
before beginning plugging operations.
D. A dry hole shall be plugged within 60 days of completion of the
well or before removal of the drill or completion rig, whichever
occurs first.
E. An oil or gas well shall be plugged within 60 days after primary
production has stopped for 12 consecutive months.
F. The Department may grant an extension of time to begin
plugging operations upon written request of the operator, if the
Department determines that the request is reasonable.
G. Surface casing may not be recovered at any location, except by
written approval of the Department.
H. After plugging a well, the operator shall erect a permanent
marker over the plugged well which:
(1) Consists of a length of pipe with a minimum diameter of 6
inches, filled with concrete;
(2) Extends at least 30 inches above the surface;
(3) Extends at least 10 feet into the well and is set in concrete;
and
(4) Has the Department and American Petroleum Institute well
identification numbers stamped or welded on the marker in a
permanent manner.
I. Upon written request by the operator or by the surface owner,
the Department may allow an offset marker to replace the marker
over a plugged well if the wellhead marker interferes with subsequent
activities, such as agriculture or construction.
J. The area immediately around the surface casing and conductor
pipe shall be permanently filled to the surface with nonporous
material to keep surface water from entering the well bore.
K. For wells in noncoal areas, the operator shall plug the well as
follows:
(1) If total depth is deeper than the cemented production casing
seat, as in an open hole completion, the open hole portion of the well
shall be filled with cement to a point 50 feet above the top of the
uncased portion of the hole;
(2) In the cemented part of the production casing, cement plugs
shall be set to extend from at least 50 feet below the base of each oil,
gas, or water-bearing zone to a point at least 100 feet above the top
of the zone;
(3) A mechanical plug, set at least 20 feet above the oil, gas, or
water-bearing zone after filling the hole to that point with nonporous
material, may be used instead of a cement plug;
(4) When multiple oil, gas, or water zones occur within 500
vertical feet of one another, they may be treated as one zone for
plugging, unless one zone has greater than hydrostatic pressure;
(5) Following the plugging of the cemented portion of the
production casing, the uncemented portion of the production casing
may be separated from the cemented portion and recovered;
(6) A cement plug shall be set 50 feet below and 50 feet above
the point of casing separation;
(7) If the uncemented portion of the production casing cannot
be recovered, oil or gas zones behind the casing shall be plugged by
perforating the casing and squeezing cement into the annular space;
(8) If the production casing is not set, a cement plug shall be
set at least 50 feet below and 50 feet above each oil, gas, or waterbearing zone;
(9) A cement plug shall be set at least 50 feet below and 50 feet
above the base of the surface casing;
(10) A cement plug of at least 50 vertical feet shall be placed in
the top of the well;
(11) After placing the top plug, the operator may be required to
cut the casing below plow depth to prevent interference with any
subsequent agricultural activities; and
(12) Nonporous material shall be placed in all portions of the
well between cement plugs.
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L. If total depth cannot be reached in plugging a well with or
without cemented production casing, the operator shall obtain
written permission of the Department for an alternate means to plug
the well.
M. If a mineable coal seam greater than 1 foot in thickness is
encountered in the drilling of a well, the operator shall contact the
Department to obtain additional plugging instructions.
N. The operator shall submit to the Department an affidavit,
within 30 days after the plugging of the well, certifying that the well
was plugged according to plans approved by the Department.
.56 Oil and Gas Bond Performance and Release Procedures.
A. The liability on the performance bond required in Regulation
.53 of this chapter is conditioned on compliance with the law,
regulations, permit, orders of the Department, and the regulations
and approvals, if any, of the Critical Area Commission for the
Chesapeake and Atlantic Coastal Bays under COMAR 27.01 and
shall continue until the:
(1) The Department approves the transfer of the drilling and
operating permit and the transferee satisfies the financial assurance
requirements, at which time the transferor’s bond shall be released;
(2) Department has approved the:
(a) Physical plugging of the well;
(b) Reclamation of the well site;
(c) Receipt of all logs, plugging records, and samples; and
(d) Performance of all requirements of these regulations and
the drilling and operating permit; or
(3) Drilling and operating permit terminates because drilling
was not started within 18 months, and the Department approves the
reclamation of the site.
B. A bond or other security shall contain a provision that it cannot
be cancelled by the surety, bank, or other issuing entity except after
not less than 90 days written notice to the permittee and Department.
At least 45 days before the cancellation date indicated in the notice,
the permittee shall file with the Department a commitment from a
surety, bank, or other issuing entity, to provide a substitute bond or
other security which shall be effective on the cancellation date
indicated in the notice.
C. The operator may apply for bond release from the Department
upon meeting all the requirements of these regulations and the
drilling and operating permit.
D. Upon written request by the operator, the Department shall
notify the surety and the principal by certified mail, return receipt
requested, when the liability under the bond has been terminated.
E. The performance bond shall be forfeited on failure of the
operator to perform in a manner set forth in the authorized drilling
and operating permit and the reclamation plan, or upon revocation
of the permit.
F. The Department shall notify the operator by certified mail,
return receipt requested, of its intention to initiate a forfeiture
proceeding.
G. Following receipt of the forfeiture notice by the operator, the
operator has 30 days to show cause why the bond should not be
forfeited.
H. On the operator’s showing of cause, the Department shall
provide sufficient time for the operator to comply with all permit
conditions.
I. On failure of the operator to show cause, the bond shall be
forfeited nisi, the Department shall give notice by certified mail,
return receipt requested, to the operator and surety of the forfeiture.
J. If the operator fails to comply with the permit conditions
following forfeiture nisi within the time period set by the Department,
the bond shall be forfeited absolute.
K. On an absolute forfeiture, the Department shall use the funds
made available by the forfeiture to complete abandonment
procedures and reclaim the area authorized by the drilling and
operating permit.
L. On an absolute forfeiture, any funds remaining after the
Department completes the abandonment procedures and reclaims the
area shall be deposited in the Oil and Gas Fund.
.57 Modification, Termination, or Transfer of Drilling and
Operating Permits.
A. A person holding a valid drilling and operating permit, and
who proposes to conduct any of the following operations not included
in the person’s current drilling and operating permit, in an effort to
obtain or increase the production of oil or gas within the State, shall
obtain a modification of the drilling and operating permit from the
Department before the person:
(1) Recompletes a well in a different oil or gas reservoir or
formation;
(2) Recompletes a well to commingle production from two or
more oil or gas reservoirs within the same formation;
(3) Stimulates a zone that has been in production;
(4) Deepens a well;
(5) Skids a drill rig 75 feet or less; or
(6) Converts from one type of well to another.
B. A drilling and operating permit terminates 18 months after the
date of issuance, if the proposed drilling has not started, unless the
Department approves an extension for good cause shown.
C. A drilling and operating permit may not be transferred or
assigned without prior written approval by the Department, and the
satisfaction of the financial assurance requirements by the transferee
or assignee; prior to approval of the transfer, the permittee shall
maintain the financial assurance requirements.
D. The transfer or assignment of a drilling and operating permit
shall be on a form provided by the Department, signed by both the
transferor or assignor and the transferee or assignee, which contains
provisions that the transferee or assignee acknowledges:
(1) Full awareness of the obligations, costs, and liabilities in
performing reclamation, plugging, and other requirements of the
drilling and operating permit and any other permit associated with
the well; and
(2) The obligation to fulfill all requirements of the permit,
Environment Article 14, Subtitle 1, Annotated Code of Maryland, and
this chapter regardless of whether the transferor or assignor started
the activity, or failed to properly perform the requirements before the
transfer or assignment.
.58 Violations of Statutory, Regulatory, or Permit Requirements.
A. A person who violates or causes an act which violates a
provision of Environment Article, §§14-101—14-120, Annotated
Code of Maryland, or this chapter, or who violates or fails to comply
with a permit issued under this chapter or an order of the
Department when due notice is given, is guilty of a misdemeanor,
and, upon conviction, the violator is subject to a fine not exceeding
$10,000 per day for each day of the offense, not to exceed a total fine
of $50,000, with costs imposed at the discretion of the court.
B. If the Department determines that there has been a violation of
a provision of Environment Article, §§14-101—14-120, Annotated
Code of Maryland, and this chapter, or a violation or failure to
comply with a permit issued under this chapter, the Department may
cause a written complaint to be served upon the alleged violator
specifying the nature of the violation.
C. After or concurrent with service of the complaint, the
Department may:
(1) Issue an administrative order requiring necessary
corrective action, including stopping work and restoration, to be
performed within the time prescribed, and providing the alleged
violator with the opportunity to request a hearing before the
Department within 10 days after receipt of the order;
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(2) Require the alleged violator to file a written report
regarding the alleged violation; or
(3) Require the alleged violator to appear before the
Department at a time and place the Department specifies to answer
the charge outlined in the complaint.
D. A written complaint or an order the Department issues shall be
served on the alleged violator personally, by certified mail, return
receipt requested, or by any method allowed for service of a
summons under the Maryland Rules.
E. Upon failure by the alleged violator to comply with the
requirements of an administrative order, a permit may be modified or
suspended by the Department.
F. Modification or suspension of a permit shall be effective
without stay upon appropriate notice to the alleged violator.
G. An administrative action or a permit suspension or
modification may not be stayed pending a hearing.
H. Under emergency conditions, such as violation or imminent
violation of an applicable State requirement, a permit may be
modified or suspended.
I. The Department may inspect a permitted site at any time in
order to determine whether conditions of the permit have been
satisfied or whether the permit should be modified, suspended, or
revoked.
J. A permit may be revoked after notice to the permittee, if the
Department determines that:
(1) The permittee or operator has failed to comply with the
requirements of an administrative order;
(2) False or inaccurate information was contained in the
application for the permit;
(3) Conditions or requirements of the permit have been or are
about to be violated;
(4) Substantial deviation from plans, specifications, or
requirements has occurred;
(5) The operator has failed to allow an authorized
representative of the Department or the Department of Natural
Resources upon presentation of proper credentials to:
(a) Enter at any reasonable time upon the permittee’s
premises where pertinent operations are conducted, or where records
are required to be kept under terms and conditions of the permit;
(b) Have access to and copy any records required to be kept
under terms and conditions of the permit;
(c) Inspect facilities to ensure compliance with the
conditions of the permit; or
(d) Inspect any monitoring equipment or method required in
the permit; or
(6) A change in any condition exists that requires temporary or
permanent modification or elimination of the permitted operation.
K. The permittee has 10 calendar days to request, in writing, a
hearing on the permit revocation to determine if the permit shall be
reinstated.
L. The provisions of this Regulation may not be construed to limit
or otherwise affect the authority of the Department to proceed
against violators under any applicable federal or State law.
ROBERT M. SUMMERS, Ph.D.
Secretary of the Environment
Title 31
MARYLAND INSURANCE
ADMINISTRATION
Subtitle 04 INSURERS
31.04.14 Life and Health Insurance Guaranty
Corporation Coverage — Notice Requirements
Authority: Insurance Article, §§2-109 and 9-414, Annotated Code of
Maryland
Notice of Proposed Action
[15-006-P]
The Insurance Commissioner proposes to amend Regulation .03
under COMAR 31.04.14 Life and Health Insurance Guaranty
Corporation Coverage—Notice Requirements.
Statement of Purpose
The purpose of this action is to update the physical address and
telephone number of the Maryland Life and Health Insurance
Guaranty Corporation in the notice required by Insurance Article, §9414, Annotated Code of Maryland, and this regulation. The Maryland
Life and Health Insurance Guaranty Corporation has moved locations
and changed telephone numbers.
Comparison to Federal Standards
There is no corresponding federal standard to this proposed action.
Estimate of Economic Impact
The proposed action has no economic impact.
Economic Impact on Small Businesses
The proposed action has minimal or no economic impact on small
businesses.
Impact on Individuals with Disabilities
The proposed action has no impact on individuals with disabilities.
Opportunity for Public Comment
Comments may be sent to Catherine Grason, Director of
Regulatory Affairs, Maryland Insurance Administration, 200 Saint
Paul Place, Ste. 2700, Baltimore, MD 21202, or call 410-468-2201,
or email to [email protected], or fax to 410468-2020. Comments will be accepted through February 9, 2015. A
public hearing has not been scheduled.
.03 Required Notice.
A. (text unchanged)
B. The notice required in §A of this regulation shall be in at least
12-point type and shall read as follows:
NOTICE OF PROTECTION PROVIDED BY MARYLAND
LIFE AND HEALTH INSURANCE GUARANTY CORPORATION
This notice provides a brief summary of the Maryland Life and
Health Insurance Guaranty Corporation (the Corporation) and the
protection it provides for policyholders. This safety net was created
under Maryland law, which determines who and what is covered and
the amounts of coverage.
The Corporation is not a department or unit of the State of
Maryland and the liabilities or debts of the Life and Health Insurance
Guaranty Corporation are not liabilities or debts of the State of
Maryland.
The Corporation was established to provide protection in the
unlikely event that your life, annuity, or health insurance company
becomes financially unable to meet its obligations and is taken over
MARYLAND REGISTER, VOLUME 42, ISSUE 1, FRIDAY, JANUARY 9, 2015
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