Received 10/13/2016 5:05:20 PM Commonwealth Court of 

IN THE COMMONWEALTH COURT OF 

 

NO.

 

 

THE MARCELLUS SHALE COALITION,
Petitioner,
V.
DEPARTMENT OF ENVIRONMENTAL PROTECTION OF THE
COMIVIONWEALTH OF and ENVIRONIVIENTAL
QUALITY BOARD OF THE OF 

Respondents.

 

PETITION FOR REVIEW IN THE NATURE OF A
COMPLAINT SEEKING DECLARATORY AND INIUNCTIVE RELIEF

 

Jean M. Mosites
PA ID. No. 206546

Kevin J. Garber
PA ID. No. 51189

BABST, CALLAND,
CLEMENTS AND ZOMNIR, P.C.
TWO Gateway Center

Sixth Floor

Pittsburgh, 15222
(412) 394-5400

Counsel for Petitioner,
The Marcellus Shale Coalition

 

IN THE COIVIMONWEALTH COURT OF 

THE MARCELLUS
SHALE COALITION,

Petitioner,

V. No.
DEPARTMENT OF
ENVIRONMENTAL PROTECTION OF
THE COMIVIONWEALTH OF
and
ENVIRONMENTAL QUALITY
BOARD OF THE COIVIMONWEALTH
OF 



Respondents.

NOTICE TO DEFEND

 

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relief requested by the plaintiff. You may lose money or property or other rights
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Telephone Number (717) 232-05 81

Dauphin County Lawyer Referral Service
Dauphin County Bar Association
213 North Front Street
Harrisburg, 171 01
Telephone Number (717) 232?7536

 

IN THE COMMONWEALTH COURT OF 

THE MARCELLUS
SHALE COALITION,

Petitioner,

V. No.
DEPARTMENT OF
ENVIRONIVIENTAL PROTECTION OF
THE COMIVIONWEALTH OF
and
ENVIRONIVIENTAL QUALITY
BOARD OF THE COMMONWEALTH
OF 



Respondents.

PETITION FOR REVIEW IN THE NATURE OF A
SEEKING DECLARATORY AND INJUNCTIVE RELIEF

AND NOW comes Petitioner, The Marcellus Shale Coalition (hereinafter
by and through its undersigned counsel, and hereby ?les this Petition for
Review in the Nature of a Complaint Seeking Declaratory and Injunctive Relief,
averring as follows:

1. This action is brought pursuant to the Declaratory Judgments Act, 42
Pa. C.S. 7531 et seq, to determine the legal rights and obligations of the parties,
and involves an actual controversy that is ripe for consideration, as appears more

fully hereinafter.

 

2. This action is also brought pursuant to 42 Pa. C.S. 7541 for
equitable and injunctive relief as additional and cumulative remedies to the
declaratory relief sought herein.

P_ar_ti??

3. Petitioner, MSC, is a non-profit corporation having its
principal of?ce and place of business located at 24 Summit Park Drive, Pittsburgh,
15275.

4. MSC is a non-profit membership organization whose members work
separately and/or together in various capacities, inter after, in regard to the
exploration, production, transmission and distribution of natural gas from the
Marcellus and Utica Shale formations.

5. Respondent, the Department of Environmental Protection of the
Commonwealth of (hereinafter is an executive
administrative agency of the Commonwealth, having its principal office and place
of business located at the Rachel Carson State Of?ce Building, 400 Market Street,
16th Floor, Harrisburg, 17105.

6. DEP is vested with the authority and responsibility, inter alia, to
implement, administer and enforce the rules and regulations contained in 25 Pa.

Code Chapter 78, applicable to conventional oil and gas operations, and Chapter

 

78a, applicable to unconventional oil and gas operations (hereafter ?Chapter 78a?
or the ?Chapter 78a Regulations?).

7. Respondent, the Environmental Quality Board (hereinafter is
a 20-member independent departmental administrative board of the
Commonwealth of having its principal office and place of business
located at the Rachel Carson State Of?ce Building, 400 Market Street, 16th Floor,
Harrisburg, . 17105.

8. EQB was established by virtue of Section of The
Administrative Code of 1929 (PL. 177), as amended May 6, 1970 (Act 120), and
is charged, inter alia, with formulating, adopting and promulgating rules and
regulations to accomplish the work of DEP and reviewing reports and advising
DEP on matters of policy.

Jurisdiction

9. This Court has original jurisdiction over this action seeking
declaratory and injunctive relief pursuant to 42 Pa. C.S. 761, as this is an action
against the Commonwealth government, its agency and its board.

10. As detailed more fully herein below, an actual controversy exists
between the parties, and MSC and its members have a direct, immediate and
substantial interest in said controversy as they are suffering and will continue to

suffer immediate, direct and irreparable harm.

 

11. MSC and its members are presently without a viable administrative
remedy for the relief sought herein.

Background Facts

12. In 2012, the legislature enacted the 2012 Oil and Gas
Act, No. 13 of February 14, 2012, PL. 87, effective immediately (in part) and on
April 16, 2012 (in part), 58 Pa. C.S. 2301 through 3504 (commonly referenced
as ?Act Act 13 was a comprehensive revision and/or replacement 1984, No. 223 of December 19, 1984, P.L. 1140, 58 RS. 
601.101 through 601.607 (?1984 Oil and Gas Act?).

13. Act 13 is largely self-implementing. MSC members are and have
been required to comply with the new requirements imposed by Act 13 and that
have been enforced by DEP since 2012, as well as all of the preexisting and
continuing Chapter 78 regulations. Act 13 did not repeal or nullify the Chapter 78
regulations.

14. Since 2012, MSC members have been required to comply with
Section 3211 of Act 13, which, among other things, specified expanded well
location notice requirements for unconventional wells as compared to those
required under the 1984 Oil and Gas Act or those required for conventional wells.
The new and expanded notice requirements include providing plats to

- municipalities where wells are to be drilled, municipalities within 3,000 feet of the

 

proposed vertical well bore, municipalities adjacent to the well, and water supply
owners and storage operators within 3,000 feet of the proposed vertical well bore.
?Water supply owners? include private property owners with water wells and/ or
springs that provide water for residential use.

15. MSC members must comply with numerous state and federal
environmental protection statutes, including, but not limited to, the Clean Streams
Law, Act 394 ofJune 22, 1937, P.L. 1987, 35 PS. 691.1?1001, the Federal
Water Pollution Control Act, 33 U.S.C. 1251?1387 (commonly referenced as
the ?Clean Water Act?), the Solid Waste Management Act, Act 97 of July 7, 1980,
PL. 380, 35 PS. 6018.101?1003, and the Dam Safety and Encroachments Act,
Act 325 ofNovember 26, 1978, PL. 1375, 32 PS. 693.1-27, along with their
implementing regulations.

16. MSC members must comply with protections for listed species under
the Endangered Species Act of 1973, 16 U.S.C. 1531-44, the Fish and Boat
Code, Act No. 175 ofOctober 16, 1980, PL. 996, 30 Pa. C.S. 101-7314, the
Game and Wildlife Code, Act 93 of July 8, 1986, PL. 442, 34 Pa. C.S. 101-
2965 and the Wild Resource Conservation Act, Act 170 of June 23, 1982, PL.
597, 32 PS. 5301-44. None of these agencies with jurisdiction and authority to
protect species de?nes ?species of special concern? or provides a process or

standards by which such species are designated.

 

17. On August 27, 2013, EQB approved proposed revisions to
Chapter 78 in a rulemaking package that included both conventional and
unconventional oil and gas well operations within its scope.

18. proposed revised Chapter 78 regulations (for both conventional
and unconventional wells) were published in the Bulletin on
December 14, 2013. Thereafter, DEP held nine public hearings at various
locations across the Commonwealth during a ninety-day comment period and
received more than 24,000 comments (including extensive and detailed comments
from MSC on behalf of its members). This comment period closed on March 14,
2014.

19. Subsequently, on July 10, 2014, the General Assembly enacted Act
126 as part ofthe Fiscal Code (Act of July 10, 2014, PL. 1053, 126 C1. 72, Session
of 2014, No. 2014~126). Act 126 required that EQB promulgate regulations
related to conventional wells separately from those related to unconventional wells.

20. Thereafter, on or about March 9, 2015, DEP revised the proposed
Chapter 78 rulemaking and released two separate chapters. Conventional oil and
gas wells remained covered under Chapter 78, while unconventional wells were
placed under a new Chapter 78a.

21. On April 4, 2015, DEP published an Advanced Notice of Final

Rulemaking seeking public comment on a draft of the proposed ?nal

 

rules for Chapter 78 and Chapter 78a. Numerous comments were again received,
including additional comments from MSC on behalf of its members. The comment
period on the ANFR closed on May 19, 2015.

22. At its hearing on February 3, 2016, EQB declined to adopt any of the
?fteen motions made by three legislative members to clarify the regulatory
language. (See Exhibit A, EQB transcript pages 

23. On February 3, 2016, EQB adopted the ?nal rulemaking package,
which included regulations for conventional wells under Chapter 78 and
regulations for unconventional oil and gas wells set forth in the new Chapter 78a.

24. The new obligations in 25 Pa. Code Chapter 78a, Subchapter 
address, among other things, the permitting and bonding of oil and gas wells,
location restrictions, onsite waste handling, spill reporting, site restoration and
more, in a comprehensive set of regulations applicable to unconventional
operations.

25. On March 24, 2016, MSC submitted comments on behalf of its
members to the Independent Regulatory Review Commission 

26. On April 12, 2016, both the Senate Environmental Resources and

Energy Committee and the House Environmental Resources and Energy

 

1 The February 3, 2016 EQB hearing was not transcribed on that day. On July 18-
19, 2016, a video of the hearing was given to a court reporter and transcribed. See
Exhibit A. 

 

Committee voted and informed the IRRC of their disapproval of the regulations,
noting that the proposed ?nal regulations were technically de?cient and the
rulemaking did not comply with the Regulatory Review Act, Act 181 of June 25,
1982, PL 633, 71 P.S. 745 .1-745.15, the Supreme Court decision
in Robinson Township v. Commonwealth of 83 A. 3d 901 (Pa.
2013) (?Robinson or of the Fiscal Code.

27. On April 21, 2016, MSC presented testimony on behalf of its
members to the IRC. On that same day, the IRRC voted to approve the ?nal
proposed rulemaking package, which included the new Chapter 78a Regulations.

28. The proposed ?nal rulemaking package was submitted to the
Of?ce of the Attorney General for approval on June 27, 2016.

29. The Of?ce of the Attorney General approved the rulemaking package
on July 26, 2016, as amended to remove the revisions to Chapter 78 applicable to
conventional oil and gas operations that had been abrogated by the 
Grade Crude Development Act, Act 52 of 2016, PL. 379, No. 52. Other than the
de?nition of ?mine in?uenced water,? no substantive changes were made to
Chapter 78a as approved by BOB on February 3, 2016 under the direction of the
Attorney General.

30. The Supreme Court issued its decision Robinson

Township, et al., v. Commonwealth of Public Utility Commission, et

 

aL, No. 104 MAP 2014, fn.3 and 18 (Pa. 2016) (hereinafter ?Robinson on
September 28, 2016, noting that Sections 3215(0) and of Act 13 were enjoined
in 2013 under Robinson 11.

31. The ?nal Chapter 78a Regulations were published in the 
Bulletin on October 8, 2016 and took effect immediately. 2

32. MSC members must comply with Chapter 78a Regulations and have
been at risk of enforcement for non?compliance by the Department on every day
since publication on October 8, 2016. These regulations are not prospective and do
not provide for gradual implementation and effectiveness, which causes immediate
harm and unlawful burdens, as explained in the counts below.

33. The Chapter 78a Regulations contain sweeping and far-reaching
changes to the regulations in Chapter 78, many of which signi?cantly,
substantially, immediately and unreasonably burden MSC and its members.

34. MSC avers that portions of the Chapter 78a Regulations, attached as
Exhibit B, are unlawful, illegal, void and unenforceable for a variety of reasons,
including, but not limited to, the following:

a. The regulations were enacted without statutory authority;

 

2 This Petition for Review relates only to certain provisions regarding
unconventional oil and gas well operations that were ?nalized in Chapter 78a and
does not address Chapter 78.

 

b. They con?ict directly with and/or are contrary to the express
provisions of other relevant statutes and regulations applicable to the industry;

0. Many of the new Chapter 78a Regulations are vague because
they do not provide suf?cient notice to persons of ordinary intelligence regarding
the requirements for compliance;

d. Some sections violate the Constitutional
prohibition against special laws;

e. EQB has failed to develop criteria, and no criteria appear or are
provided in the regulations, for DEP to utilize for conditioning a permit based on
its impact to public resources and for ensuring optimal development of oil and gas
resources and respecting the property rights of oil and gas owners;

f. EQB failed in its statutory duty to draft and adopt the
regulations, deferring entirely to DEP to take full responsibility for every word in
every iteration promulgated; and

g. The rulemaking process for the formulation of the regulations
failed to comply with the Regulatory Review Act, as shown in part by an

inadequate Regulatory Analysis Forrn 3

 

3 An RAF is required under the Regulatory Review Act to provide the IRRC with
information necessary for its review, including, among other things, the statutory
authority, a statement of need, estimates of direct and indirect costs, identi?cation
of the financial impact, a description of the economic and social impact of the

10

 

35. According to the Department, the Chapter 78a Regulations challenged
herein have the potential to impose an initial cost between $40 and $70 million,
and up to $16 million annually thereafter, upon MSC members and the
unconventional well industry generally.4

36. Certain sections of the Chapter 78a Regulations, as referenced
speci?cally below in Counts I through VII, and as attached in Exhibit B, impose a
direct, immediate, substantial and irreparable harm on MSC and its members to
such an extent that they should be stayed pending review and adjudication by this
Court. MSC has ?led, simultaneously with this pleading, a request for expedited
review and a request to stay the challenged portions of Chapter 78a and enjoin
DEP from implementing and] or attempting to enforce these regulations until such

time as their legality has been ?nally determined.

 

regulation on small businesses, and a description of the data upon which the
regulation is based. The IRRC docket for this rulemaking, IRRC No. 3042,
contains all comments received, the text of the proposed and ?nal regulations, and
two versions of the RAF submitted by DEP. See:
The 2016 RAF was not
published for public review or comment. Portions of the RAF referenced herein
are attached as Exhibit C.

4MSC has challenged, and continues to dispute, cost estimates as inaccurate
and inadequate to satisfy obligations under the Regulatory Review Act, but
includes estimates herein as admissions by the Respondents that the
challenged provisions will impose new costs on MSC members. As noted in the
counts below, DEP also improperly estimated zero costs for certain new
obligations created in Chapter 78a.

11

 

Count I
Declaratory Relief
Public Resources
Sections 78a.1 and 78a.15( f) and 

37. The averments contained in paragraphs 1 through 36, above, are
incorporated herein and reasserted as though set forth fully at length.

38. Section 78a.15 injects an entirely new, back door, ?pre-permitting?
scheme into the oil and gas well permitting process without statutory authority.
Section 78a.15(f) requires applicants to notify and provide information to newly
defined ?public resource agencies? if the proposed limit of disturbance of a well
site is located within a certain distance of a ?public resource? including ?in a
location that will impact other critical communities,? common areas of school
property, playgrounds or wellhead protection areas. Newly designated public
resource agencies may then comment on the permit application and suggest
conditions to be imposed in the permit.

39. Pursuant to Section 78a.l, the term ?critical communities? is de?ned
to include any ?species of special concern? identi?ed on a Natural
Diversity Inventory receipt, including species that have not been listed
by any agency as threatened or endangered.

40. DEP stated in the preamble of the rulemaking published in the

Bulletin that it ?will consider the potential impacts to other public

resources identified during the permitting process presumably adding new and

12

 

evolving obligations to protect unknown ?public resources? that are not identi?ed
or de?ned by statute or regulation. (See Exhibit B, Preamble at 6446 (emphasis
added)).

41. Neither Section 78a. '15 nor any other section of the Chapter 78a
Regulations creates criteria required under Section 3215(e) of Act 13, criteria that
DEP must utilize for conditioning a well permit based on its impact to public
resources and for ensuring optimal development of oil and gas resources and
respecting property rights of oil and gas owners.

42. Section 78a.15(g) purports to authorize DEP to consider comments
of municipalities in the well permit process prior to conditioning a well permit
based on impacts to public resources.

43. DEP asserted in its RAF that these sections impose new costs of over
$800,000 annually, but declined to provide any estimate for the costs of mitigation
that would be required, new costs that will necessarily be incurred.5

44. Four new de?nitions contained in Section 78a.l public resource
agencies, common iareas of school property, playgrounds, other critical
communities) and the process required by Section 78a.15(f) are unlawful, illegal,

void and unenforceable for the following reasons:

 

5 See also the Preamble regarding costs of mitigation that ?may be substantial? but
are not estimated. (Exhibit B, Preamble at 6464.)

13

 

a. There is no statutory authority for Section 78a.15(f) or the
related de?nitions in Section 78a.1. On September 28, 2016, the 
Supreme Court con?rmed that, of Section 3215 of Act 13, only Section 3215(a)
(which prescribes setback distances for oil and gas wells from buildings and water

wells) remains in effect. See Robinson 1V, fn 3 and page 18.

 

b. Neither Act 13 nor any other law provides DEP or EQB with
jurisdiction or authority over species.

c. These sections are contrary to and circumvent Sections 3212
and 3212.1 of Act 13, which expressly de?ne who can comment on or object to a
well permit application. Act 13 does not authorize newly de?ned ?public
resources agencies? or others not referenced in Act 13 to comment upon or object
to a well permit application at any time, and does not authorize DEP to create a
new or ?pre?permitting? comment and objection scheme.

d. Even if it were not enjoined, EQB failed to comply with
Section 3215(e) of Act 13 that required EQB to develop criteria for DEP to use
when conditioning well permits based on impacts to public resources and for
ensuring optimal development of oil and gas resources and respecting property
rights of oil and gas owners. Until EQB satis?es the statutory precondition to
develop such criteria by regulation, DEP has no authority to engage in any activity

associated with conditioning well permits in relation to public resources.

14

 

e. Section by which DEP would consider comments of
municipalities, is contrary to Robinson 11, which held Section 3215(d) of Act 13 to
be unconstitutional. authority to consider comments of municipalities in the

well permit process has been enjoined, an injunction that cannot be circumvented

by rulemaking.
f. These combined provisions and process violate due process.
g. These combined provisions and process violate the

Commonwealth Documents Law, Act of July 31, 1968, PL. 769, No. 240, 45 PS.
1102 et seq, because they circumvent notice and comment rulemaking by
creating a binding norm through an ever changing PNDI database that is not
populated through notice and comment rulemaking procedures and, therefore,
effectively allowing DEP or unknown third parties to randomly and arbitrarily
change regulatory requirements without formal rulemaking.

h. These combined provisions and process are void. for vagueness
because no mechanism is provided for advanced knowledge of new obligations
that will arise from a PNDI receipt generated from a database that can change on a
daily basis without public notice.

i. These combined provisions and process are unreasonable
because, among other things, no standard is provided by which DEP conditions

permits to allegedly protect ?public resources? from impacts described by the

15

 

?public resource agencies,? the universe of public resources to be protected is
unlimited, unknown and unknowable, and the coordination with the multitude of
new public resources agencies is impractical and unduly burdensome.

j. These combined provisions and process violate the
Constitution, Article 111, Section 32.

k. The process by which these sections were promulgated failed to
comply with the Regulatory Review Act because the RAF provided no cost
estimate related to the consultation or mitigation that is required under the new
processes in these sections, while conceding that the ?cost may be substantial
depending on the location of the well site.? (See Exhibit C, RAF at 87.)

WHEREFORE, MSC respectfully requests that this Honorable Court enter
judgment in its favor and against DEP and EQB, and declare that Sections

)3 cc

and the de?nitions of ?public resource agencies, other
critical communities,? ?playgrounds,? and ?common areas of school property? in
Section 78a.l be stricken as unlaw?il, void and unenforceable.
Count II
Declaratory Relief
Area of Review
Sections 78a.52a and 78a.73(c) and 

45. The averments contained in paragraphs 1 through 44, above, are

incorporated herein and reasserted as though set forth fully at length.

16

 

46. Sections 78a.52(a) and 78a.73(c) and impose new and excessive
obligations that require well Operators to identify active, inactive, orphan,
abandoned and plugged wells before drilling, to monitor certain identi?ed wells
before hydraulic fracturing, and to plug orphan and abandoned wells that an
operator alters, without a de?nition or standard for the meaning of ?alter.?

47. Section 78a.73(c) creates an unreasonable and unwarranted
obligation during stimulation activities, to Visually monitor any orphan, abandoned
or plugged well that has an unknown true vertical depth, when such wells are
within 1,000 feet of the vertical or horizontal wellbore of the well to be completed.

48. DEP asserted in its RAF that these provisions impose new costs that
may exceed $11 million annually. (See Exhibit C, RAF at 88.)

49. These sections are unlaw?ll, illegal, void and unenforceable for the
following reasons:

a. No statute authorizes the new ?area of review? inquiry.

b. Section 3220 of Act 13 does not authorize DEP to compel any
person to plug an orphan or abandoned well, other than a prior owner or operator
of that well who received economic benefit from it.

c. These sections are void for vagueness, in part because DEP
admitted, at the February 3, 2016 EQB meeting, that it does not intend to

implement them as written and that they require ?irther technical guidance

17

 

documents to clarify the obligations created under them. (See Exhibit A,
Transcript at pages 89-92.)

(1. These sections are unlawful and unreasonable because DEP has
granted to itself unlimited authority and discretion to require additional measures
without any express standard, potentially making a determination that no hydraulic
fracturing may be conducted at all, depriving operators of property rights. See
Section 

e. Section 78a.73 is unlawful and unreasonable because it
imposes an arbitrary and capricious requirement to monitor certain orphan,
abandoned or plugged wells simply because their true vertical depth is unknown.

f. These sections are contrary to property law and
they require access to properties that are not within the ownership or control of
MSC members, requiring operators to choose between non-compliance and
trespass.

WHEREFORE, MSC requests that this Honorable Court enter
judgment in its favor and against DEP and EQB, and declare that Sections 78a.52a

and 78a. 73 and be stricken as unlawful, void and unenforceable.

18

 

Count 111
Declaratory Relief
Onsite Processing
Sections 78a.5 8( f)

50. The averrnents contained in paragraphs 1 through 49, above, are
incorporated herein and reasserted as though set forth fully at length.

51. Section 78a.58(f) requires that onsite processing activities, other than
?uid handling activities described in Sections 78a.58(a) and comply with the
Solid Waste Management Act I

52. Onsite processing of residual waste includes activities and substances
other than those described in Sections 78a.5 8(a) and such as processing drill
cuttings, among others.

53. SWMA compliance for processing cuttings and other wastes requires
permits, bonds, containment, recordkeeping, reporting, and other obligations that
have not previously been required for activities on well sites.

54. Section 78a.58(f) has no transition or grandfathering provisions,
which requires MSC and its members to stop previously lawful activities for
unknown periods of time to obtain permits, approvals, equipment and materials to
continue common well site activities.

55. This section is unlawful, illegal, void and unenforceable because it

con?icts with the express SWMA well site exemption contained in 3273.1 of Act

13. Act 13 provides that no permit or bond will be required under the SWMA for

19

 

any pit, impoundment, method or facility used for disposal, processing or storage
of residual wastes generated by drilling or production of oil and gas wells where
the well is permitted and bonded under Act 13.

WHEREFORE, MSC respectfully requests that this Honorable Court enter
judgment in its favor and against DEP and EQB and declare that Section 78a.58(f)

be stricken as unlawful, void and unenforceable.

Count IV
Declaratory Relief
Impoundments
Sections 78a.59b and 78a.59c 

5 6. The averments contained in paragraphs 1 through 55, above, are
incorporated herein and reasserted as though set forth fully at length.

57. Sections 78a.59b and 78a.59c impose extensive and burdensome new
requirements for impoundments, including impoundments that store fresh water
(referred to as ?well development impoundments?).

58. Under Section 78a.59b, owners or operators of existing well
development impoundments must upgrade or close them within one year of the
effective date of Chapter 78a, by October 10, 2017.

59. There is no grandfathering for liners or fencing that are now

required for existing well development impoundments.

20

 

60. DEP asserted in its RAF that Sections 78a.59a and 78a.59b impose
new costs up to $8 million initially and up to $3 million annually for well
development impoundrnents. (See Exhibit C, RAF at 96-97.)

61. Under Section 78a.59c, owners or operators of existing centralized
impoundments must close or re-permit them under the within three years
of the effective date of Chapter 78a, by October 8, 2019.

62. MSC members own and operate centralized impoundments that were
built in accordance with regulations and detailed guidance developed by DEP,
following review and approval by DEP.

63. - DEP asserted in its RAF that Section 78a.59c imposes initial costs up
to $65 million for existing centralized impoundments and up to $900,000 annually
thereafter. (See Exhibit C, RAF at 98.)

64. These sections are unlaw?il, illegal, void and unenforceable for the
following reasons:

a. Act 13 does not authorize DEP to develop regulations for
freshwater impoundments off well sites, which are regulated under the
Clean Streams Law and the Dam Safety and
Encroachments Act.

b. The SWMA does not require a permit for centralized storage

impoundments as required under Section 78a.59c.

21

 

c. The obligations for freshwater and centralized storage
impoundments violate the Constitution, Article Section 32.

d. These provisions are unlaw?il and unreasonable because they
require the upgrading or closure of centralized impoundrnents that were
constructed under applicable law and fail to grandfather existing well development
impoundments.

WHEREFORE, MSC respectfully requests that this Honorable Court enter
judgment in its favor and against DEP and EQB and declare that Sections 78a.59b
and 78a.59c, be stricken as unlawful, void and unenforceable.

Count 
Declaratory Relief
Site Restoration
Section 78a.65

65. The averments contained in paragraphs 1 through 64, above, are
incorporated herein and reasserted as though set forth fully at length.

66. Section 78.65(b) requires a duplicative site restoration plan, in
addition to the site restoration plan required under Clean Streams Law, for well
sites over ?ve acres. Section 78.65(b) exceeds the statutory authority provided in

Act 13, Section 3216, which requires operators to comply with Clean Streams Law

and its regulations for earth disturbance related to oil and gas operations.

22

 

67. Section purports to require well sites to be returned to
approximate original conditions, which is beyond statutory authority under either
Act 13 or the Clean Streams Law.

68. Section improperly, arbitrarily and capriciously
imposes site restoration obligations, as determined by DEP, regarding the areas
needed to safely operate the well.

69. Section 78a.65(d) improperly imposes obligations on well sites of less
than ?ve acres, in conflict with existing regulations and approvals developed under
the Clean Streams Law.

70. Under the Clean Streams Law regulations set forth at 25 Pa. Code
wells permitted under Chapter 78 need not comply with expensive and
intrusive Post Construction Stormwater Management calculations and Best
Management Practices required under Section 

71. Section 78a.65 is unlaw?il, illegal, void and unenforceable for the
following reasons:

a. This section violates the Commonwealth Documents Law
because the text of the ?nal regulation enlarged the original purpose of the
proposed regulation published for public comment by the: addition of newly
required restoration plans that are unnecessary and duplicative of the requirements

under the Clean Streams Law, which apply to the same earth disturbance activities,

23

 

and (ii) elimination of an exemption available under the Clean Streams Law from
post?construction requirements for well sites. The elimination of this exemption
that was otherwise available and undisturbed under the proposed regulation
requires republication by EQB for comments by the public.

b. This section conflicts with the regulations under the Clean
Streams Law at 25 Pa Code 102.8(n) because it imposes post-construction storm
water obligations on well sites having exemptions under Chapter 102.

c. This section is void for vagueness because DEP has indicated
that it will not be implemented as written, and EQB failed to adopt clarifying
language before the section was ?nalized.

d. This section is unreasonable and imposes burdens beyond
statutory authority provided in Section 3216 of Act 13, which allows for supplies,
equipment and storage on producing well sites according to operator needs, not
arbitrary and capricious DEP determinations.

e. The process by which these sections were promulgated failed to
comply with the Regulatory Review Act because the RAF contains no cost
estimate related to the new requirements under these sections, costs that will

necessarily be incurred. (See Exhibit C, RAF at 101.)

24

 

WHEREFORE, MSC respectfullyrequests that this Honorable Court enter
judgment in its favor and against DEP and EQB and declare that Section 78a.65 be
stricken as unlawful, void and unenforceable.

Count VI
Declaratory Relief
Remediation of Spills
Section 78a.66(c)

72. The averments contained in paragraphs 1 through 71, above, are
incorporated herein and reasserted as though set forth fully at length.

73. Section creates an ambiguity as to Whether it is
mandatory for the oil and gas industry to follow the procedures of a remediation
program that is voluntary for all other industries in under the
Land Recycling and Environmental Remediation Standards Act, 32
PS. 6026.101 et seq. (commonly referenced as ?Act 

74. Section 78a.66(c) creates and imposes additional deadlines, reports
and noti?cation obligations on the oil and gas industry beyond those required by
Act 2 or any applicable statute.

75. Section 78a.66(c) improperly requires small (over 42 gallons) spills of
brine, a relatively harmless substance, to be remediated under Act 2, with added

conditions for reports and submissions to DEP on a timeline that is not imposed on

any other industry.

25

 

76. Section 78a.66(c) is unlawful, illegal, void and unenforceable for the
following reasons:

a. DEP has no authority to require any person to follow the Act 2
process, which is a voluntary program to obtain relief from further cleanup liability
at the option of the remediator.

b. The remediation obligations violate the 
Constitution, Article Section 32.

c. This section is unreasonable because it imposes, without
justi?cation, unique obligations on the oil and gas industry above and beyond those
for any other industry.

d. The process by which these sections were promulgated fails to
comply with the Regulatory Review Act because the RAF includes no cost
estimate for additional notices, reports and timelines that are required under the
new remediation procedures in these sections. DEP disregarded public comments
that remediation costs for a single incident could increase from $10,000 to
$25 0,000 under the new requirements. (See Exhibit C, RAF at 101.)

WHEREFORE, MSC respectfully requests that this Honorable Court enter
judgment in its favor and against DEP and EQB, and declare that Section 78a.66(c)

be stricken as unlawful, void and unenforceable.

26

 

Count VII
Declaratory Relief

Waste Reporting
Section 78a.121(b)

 

77. The averments contained in paragraphs 1 through 76, above, are
incorporated herein and reasserted as though set forth fully at length.

78. Section 78a.12l(b) requires operators to submit waste
generation reports, even though Act 173 of 2014, Section 3 of the Unconventional
Well Report Act (58 PS. 1003) requires operators to report oil and gas
production only on a basis.

79. DEP asserted in its RAF that this section imposes annual costs up to
$600,000. (See Exhibit C, RAF at 104.)

80. Section 78a. 12l(b) is unlawful, illegal, void and unenforceable for the
following reasons:

a. The section is contrary to Act 173 of 2014, which revised
production reporting to a basis but did not change or authorize a change in
waste generation reporting.

b. This provision is unreasonable because it imposes excessive
costs with no discernible bene?t and imposes waste reporting obligations on this
industry that are stricter than those for any other industry in the Commonwealth.

c. This section con?icts with 25 Pa. Code 287.52, which

requires only bi~annual waste production reports.

27

 

WHEREFORE, MSC respectfully requests that this Honorable Court enter
judgment in its favor and against DEP and EQB, and declare that Section
78a.121(b) be stricken as unlawful, void and unenforceable.

Count 
Iniunctive Relief

81. The averments contained in paragraphs 1 through 80, above, are 
incorporated herein and reasserted as though set forth fully at length.

82. MSC avers that it is entitled to an immediate stay of the regulations
speci?cally identified in Counts I through VII, above, as there is an urgent
necessity to avoid an injury that cannot be compensated by damages; that greater
injury will result from refusing rather than granting the relief requested; and that
DEP and EQB should be enjoined from implementing these sections until a ?nal
determination of their legality and enforceability is established.

83. The Chapter 78a Regulations were effective upon publication on
October 8, 2016, and MSC, its members and other unconventional oil and gas
operators have been obligated to comply with those regulations as of the date of
publication. There is no general provision in the regulations for grandfathering
existing operations or operations that have already commenced and are ongoing.

84. MSC members are and have been in the midst of preparing well

permit applications for new or ongoing oil and gas operations and have expended

28

 

signi?cant amounts of money and personnel time in doing so. The immediate
implementation of Section 78a.15(i) causes immediate harm and means that these
preparations and expenditures have been wasted, to the extent that the well permit
applications prepared but not yet submitted, or currently pending review by DEP
after submission, must meet new and additional requirements and burdens.

85. The regulations provide no accommodation or procedures regarding
what is required regarding in?process permitting and other ongoing operations.
Without grandfathering or a transition of pending and ongoing activities, operators
must begin processes and activities anew because of additional requirements
imposed by the new regulations, incurring new costs and suffering immediate
harm.

86. Regarding wells that have already been drilled and/or are in the
process of being drilled, MSC members may have to cease drilling or may not be
able to complete those wells given the new and ambiguous obligations under
Sections 78a.52a and 78a. 73 related to the area of review for abandoned or orphan
wells.

87. MSC members currently processing any waste on well sites other than
?uids are required under Section 78a.58(f) to comply with the SWMA, thereby
having to stop and restart previously law?ll activities and operations, incurring

costs and delays related to new permitting under the SWMA, as well as disposal,

29

 

containment, equipment, contractors and staf?ng needed for compliance and
suffering immediate harm.

88. MSC members in the process of restoring well sites must stop and re-
start restoration efforts in order to comply with the new Section 78a.65
requirements, thereby incurring immediate new costs and suffering immediate
harm, and possibly having to waste significant amounts of money and manpower
already invested.

89. MSC members in the process of remediation must stop and re?start
cleanup efforts in order to comply with new Section 78a.66 requirements, thereby
incurring immediate new costs and suffering immediate harm, and possibly having
had to waste significant amounts of money and manpower already invested.

90. MSC members owning or operating existing freshwater and
centralized impoundments must comply with new obligations for design,
construction and permitting impoundments that have already been built under prior
law or close existing centralized impoundments.

91. MSC members with wells in production are now suddenly required to
spend significant amounts of money and manpower to begin waste
reporting that is not required otherwise.

92. The challenged provisions require MSC members to hire or reassign

staff, train and retrain employees, change operations that span the life of the well,

30_

 

develop and implement new recordkeeping and reporting systems, retain
consultants with various types of expertise, acquire newly required equipment and
materials, obtain permits under the SWMA, and discard valuable facilities and
structures that were lawfully installed within the past six years.

93. There is an urgent necessity to avoid immediate, substantial and
irreparable injury to MSC and its members that cannot be compensated by
damages. A greater injury will result from refusing rather than granting the relief
requested.

94. Granting of a stay and injunction will not harm DEP or EQB and
will not affect other unchallenged portions of Chapter 78a, the self-implementing
provisions of Act 13, or the multitude of existing state and federal environmental
laws and regulations with which MSC members must comply.

95. Granting a stay of the challenged provisions will not harm the public
or the envirOnment because MSC members must comply with the self?
implementing provisions of Act 13 as well as a comprehensive framework of
existing environmental laws.

96. DEP has demonstrated no urgency as it undertook a multi-year
development of the regulations since 2012, and industry activity has substantially

declined since 2012. Unconventional wells drilled between January and July of

31

 

each year, for example, declined from 790 in 2014, to 512 in 2015, to 230 wells
drilled in 2016.

97. If the stay and injunction requested are denied, MSC and its
members will suffer immediate, substantial and irreparable harm and be subject to
enforcement by DEP for the challenged sections that became effective immediately
upon publication. The revisions became effective without grandfathering
provisions or accommodation for the massive number of regulatory revisions in the
rulemaking.

98. MSC is therefore entitled to a stay of the speci?c Chapter 78a sections
referenced above in Counts I through VII and an injunction with respect to the
implementation and enforcement of those regulations until such time as this Court
renders a ?nal determination as to their legality. An Application for Special Relief
is being filed with this Court concurrently with this Petition for Review.

WHEREFORE, MSC respectfully requests that this Honorable Court enter a
stay of the implementation and enforcement of the regulations referenced
specifically in Counts I through VII, above, issue an injunction prohibiting DEP
from implementing and/or enforcing any of those regulations until the legality and
enforceability of the regulations is determined, and grant such other and further
relief as may be necessary and appropriate under the circumstances, including

awarding MSC its costs and attorney fees.

32

 

Date: October 13, 2016

33

Respectfully submitted,

BABST, CALLAND, 
AND P.C.

  
  

By 
Kevin J. Garber
PA ID. No. 51189

TWO Gateway Center

Sixth Floor

Pittsburgh, 15222
(412) 394?5400

Counsel for Petitioner,
The Marcellus Shale Coalition

VERIFICATION

1, David J. Spigelmver President of the Marcellus Shale
Coalition, do hereby state that I am authorized to execute this Veri?cation on its
behalf, and that the averrnents of fact contained in the foregoing Petition for
Review in the Nature of a Complaint Seeking Declaratory and Injunctive Relief, as
those facts have been made known to me, are true and correct to the best of my
knowledge, information and belief. This Veri?cation is made subject to the
penalties of 18 Pa. C.S.A. Section 4904 relating to unsworn falsification to

authorities.

Date: October 13. 2016 gt 

David J. Siaigelmyer

 

Petition - Ex. A

 

 



 



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Page 1

Txansoript of VideoXAudio DVD of the DEP.
Environmental Quality Board Meeting held on February
3rd, 2016, transcribed at the offices of Morse,
Gantverg Hodge, Inc., 112 Waehington Place, Suite
1R, Pittsburgh, 15219, on Monday and
Tuesday, July 18 and 19, 2016, by Jill.A. Oliver,

Court Reporter.

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Page 2 Page a
l. OF DVD 1 at representing secretary of
2 MR. QUIGLIEY: Good morning. everyone. The 2 transportation Leslie Rioh ards.
3 February 3rd, 2016 of the Emdronmental Quality 3 MS. BROWN: Gladys Brown, chair of the
4 Board is sailed to order. I'm John Qt?gliey, =1 Publie Utility Chair Commission.
5 secretary of the Department of Environmental 5 MR. Greg Vitali. State
6 Protection and chair of the board. 6 Representative from DBIHWEYG 311d ?50131301116?
'7 I just want to note for everyone what 7 Counties.
8 should be obvious. We are broadcasting this 3 A VOICE: Jonathan 
9 meeting live. So all of your microphones are on. 9 oitemate for Representative John Mallet. I will
1 0 You don't need to push anybuttona. They?re all 1 0 note that Representative Matter will be here.
1 1 being controlled remotely 1 1 ?sh caught in traf?c.
1 2 Let?s go around the room and take a moment IL 2 MR. FOX: I?m Richard Fox alternate for
13 to introduce ourselves. 1 3 Senator John Yudioholt.
1 4 MS. CHILDE: I?mKito Childe, director of 1 4 MR. YAW: Geno Yaw. chaiman of the Senate
1 5 the Borough of Regulatory Counsel for DE and 1 5 and Enviromnentai Resontees and Emery Comnittee.
1 a counselor to the board. 16 MR. DIMWITEO: Michael DJmatteo offhe
1 7 MS I?m Shanon Watkins. I'm the 17 Game Commission representing Matthew
1 8 state epidemiologist and director for theBormIgh 1 Bough.
9 of Environmental and Epidemiology for the State 1 9 MR. WAITE: Burt Waite, Citizens Advisory
2 0 of Flo?da. 20 Council,
2 1 MIL SMIIH: Michael Smith, executive deputy 2 1 MR. ARWAY: John Alway, executive director
2 2 secretary. Department of Agriculture rqtresenting 2 2 of Fish and Boat Commission.
2 3 Russell Rodding. 2 3 MS. lasts Edlnger, DEF regulatory
2 4 MR. OPIYO: Paul Opiyo. alternate for 2 4 coordinator.
2 5 Secretary Dennis Devlin, PCD. 2 5 MR. MCDONAID: Pat McDonald. polioy
Page 3 Page 5
1 MR. WALLESSUR: John Walletsar. Citizen's 1 director at DEF.
2 Advisory Counsil. 2 ME. Thank you. all. let's get
3 MR. WELSH: Don Welsh, Citizen?s Advisory 3 right to work. The ?rstitem ofhusiness before
4 Council. 4 the board todayis the approval of minutes from
5 MR. FINK: William Fink, Citizen?s Advisory 5 the November 17th, 2015 hoardmeetlng. You all
6 Council. 5 have those minutes. Are there any corrections to
7 MS. CARROW: Carmw, Citizen?s 7 the minutes? Is there a motion to adopt the
8 Advisory Council. 8 minutes of the November 1 7th meeting? Eileen and
9 MR. ROBJNSON: Sam Robinson; I'm 9 seoond by Representative Vitali.
1 0 representing secretary of Policy and Planning 1 0 'Ihose in favor ofthe motion please say
1 1 John Hanger. 1 ?Aye.?
12 MR. MCILBAREN: Dong Motoaren, alternate for 12 (Thereupon, there was a chorus of eyes.)
1 3 Jim Vaughn. Historical and Museum Commission. 1 3 MR. QUIGLIEY: Any opposed?
4 MS. NOLAN: Goodmoming. Liz Nolan, I?m 1 4 (No response.)
1 5 an attorney with the Of?ce of Chief Counsel, 1 5 MR. QUIGIIBY: Next order the moticm is
1 6 Borough of Regulatory Counsel. 3. 6 adopted to approve the minutes as presented
1 7 MR. PERRY: Scott Pony. Deputy Secretary 1 7 ?The next item of business before the hoal?
1 for Of?ce of Oil and Gas Managenoot. 1 8 today is consideration of the ?nal miemaklog to
1 9 MR. Good mooning. Kart 19 revise Chapter T8 and Title 25 ofthe
2 0 Klapkowsld. director of the Borough of Oil and 2 0 Code related to conventional oil and
2 1 Gas Flaming Management PA DEF. 2 1 gas wells and to establish a new ohapterJBA
2 2 MS. CERIANI: Good morning. Eileen 22 related to unconventional oil and gas wells. .
2 3 Cipriaoi representing the secretary Kathy 2 3 Here's how we?re going to proceed this
2 a Mauderino, the Department of labor and Industry. 2 4 morning, The board will ?rst hear a
2 5 MR. COHEN: Rodger Cohen, policy director 2 5 presentation ?ora the Deparhnent of Eoviromnental
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1 MR. QUIGLLEY: All those in favor of this 1 MR. MAKER: I'm not sure where you see 'a
2 motion please onto question. Go ahead. 2 delay. We have this questionhefore us. Wehavc a
3 MR. MAHER: Ithinlc it might be a elegant 3 Chapter 78 and Chapter 78A. The motion is not ti
4 solution to ahelahoring problem. The a about postponing. The motion is about i ?15
5 legislature directed in statues it was enacted by 5 considering them as directedby statue ..
6 to law that there should be separate rulemaldng 6 separately, and of course the board can act to 
7 dealing with conventional from that dealing with 7 not regard the statute, but I think that will
8 unconventional, and 1 have considerable concerns 8 establish a record that?s unfortunate for when a
9 that that has been disregarded to this point. 9 this gets challenged in com-t on that issue. 
1 This motion would at least allow the EQB to have 1 0 MR. QUIGLYEY: Are there any other comments i
1 1 a hit ofa straight face and say that it did in 1 onMr. Waitc's motion? John. 
2 fact promulgate regulations separately. It's not 1 2 MR. ARWAY: Can I ask the department's 
1 3 much of a Band?Aid, but. it's something. 1 3 position on the motion? 
Li 4 Otherwise, I think we've got a whole problem that 4 MIL QUIGIJEY: We would he opposed. All 
1 5 the whole thing will disappear in the courts. 1 5 right. The motion is to amend the original 2
1 6 MR. QUIGLIEY: Representative Vitali. 6 motion to sepaxately consider Chapter 78 and 78A. 
1 7 MR. VHALI: I'm going to oppose to this. 1 '3 All those in favorplease say, "Aye." a
18 l've seen nothing other of years 1 8 (Theseupon, there was a chorus of eyes.) Q.
1 9 other than the endless attempt by the 1 9 MR. QUIGLIEY: How about raising of hands? a
2 0 conventional chilling industry to 2 0 Five. All opposed. Motion fails.
2 1 process. We have-been ?ve years in the making. 2 1 We?re still on the question. Are there any i
2 2 We've heard the 28,000 public comments. Eveqzone 2 2 other questions or comments? 
23 has had opportunity to comment on this. The 2 3 MK MAHER: We have pending amendments. ll
2 4 comments have been responded to. Inthe 2 4 MR. QUIGLEEY: Well, you got to bring itto i
2 5 legislature there's been an unconstitutlon al. to 5 the floordothisin tWo differentilscal codoh?ls. It?s 1 no mass; Consider my package of '5
2 my conclusion simply that the conventional 2 mnendtaents brought no the ?oor please. a
3 industry simply does not want to be regulated, 3 MR. QUIGLIBY: Wouldyon nice to makes 3
4 and does not want to pay the cost, and there is 4 motions: discuss to put onthe table your
5 vetyreal costto this delay. We're not doing 5 ?rst amendtnentt'epnesente?ve?
6 this in a vacuum. When we do nothing, it means 6 MR. MAKER: I'll make emotion diatwe I
7 that the public is subject to lesser standards, consider Amendment No. i, centralized hepoundment 
8 the on?ronment is subject to lesser protection 8 de?nition. . 
9 standards. I?m really simply sick and tired of 9 me QUIGLIEY: I believe all members have 
the way that the dn'lling industry has delayed that nifoneation before them. There's a motion 3
1 this process, has delayed other things like the 1 on the ?oor to ooasiderRepresentative how 
12 severance tax, the control they have over all 12 about we call them Representative Mallets a
13 this andIthink it?s just yodloiow, one of 1 3 Amendments and we'll go through this process to 
1 4 the things that [have heard Mr. Maher say on the 1 4 try to keep it straight for Li
1 5 house ?oor many times is that theperfeot should 1 5 There is a motion Representative has i
1 6 not he an enemy of the good, and I've also heard 1 6 made a motion to consider Amendment No. 1. Is 3
17 that there will never be a perfect bill. Well, 1 7 there a second? All right. Second by Bart. On it
1 8 that?s true here. Nothing will be perfect, but 1 8 the question. Representative? i
1 9 it?s good. Its needed. It's time to put all of 19 MR. This package ofatneadments is 
2 0 this nonsense and delay aside. It's time to move 2 intended to largely be technical clean up for 
2 1 forward. Lets vote no on this motion, no on 2 1 clarion Ido have concerns. as hwas expresaing 
2 2 this amendments, get these things in places and 2 2 the overarching process, hot these 
2 3 get the public and the environment protected. So 2 3 amendments do not got to that. Those amendment? 
2 4 I?ll be one vote on this. 24 are largely This oneJ for 
2 5 MR. QUIGLIEY: Onto question. 2 5 instance, you might have noticed in your reading
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Page 7 0 Page 7 2
of Chapter 78 and ?3 BA that centralized 1 subject to this de?nition.
2 impou?dmentis not socially defined that it 2 Again, it?s just in the interest of clarity
3 idertifythat it deals with waste water. It 3 that this offered, and that's it.
4 merely makes a reference a form. So this 4 MR QUIGLIBY: Other questions? John.
5 provides alittle clarifying language to those 5 MR. ARWAY: What?s the department?s
6 who are reading the centralizad impoundmcut parts 6 position on that?
7 of the regulation will understand what it is that 7 MR QUIGLIEY: I'll ask Scott and company.
8 they?re reading out. 8 MR. PERRY: This occurred to Joe Adams to
9 MR QUIGLIBY: Are there any questions or 9 jump in here, but this de?nition has undergone a
10 comments? We have a motion that?s been seconded 1 fairly considerable amount ofreviow during the
1 1 to amend the motion on the ?oor to include 1 1 development of the n?emaldng itself. So the
1 2 Representative Mahcfs Amendment No. . All 1 2 concept here Is not of amending this
1 3 those in favor please say, "Aye,? and again P11 1 3 de?nition has certainly one that's been
14 ask you to raise your hands. Five. Allthose 14 discussed in our common discuss document, but one
3. 5 opposed? Okay. The motion fails. 1 5 of the things that's of concern to us is that
1 6 Proceed, Representtuive, with your second 1 5 just because water is being discharged under an
1 7 one. 1 7 NTDES pennit does not necessarily mean that it is
18 MR MAHER: Yes. I?m pretty impressed that 1 8 clean and in particular not clean for any water
19 even for in a matter of a clarifying de?nition 1 9 shed in which it may be stored in. Sewage is
20 that the department would object, butlwill 2 discharged under an permit. Industrial
21 proceed. The second amendment deals with the 2 3. wasteis charged under an permit and
2 2 de?nition of mine in?uenced water. Currently 2 2 ?'equen?y they rely on and frequently they rely
2 3 the allows water horn mines 2 3 on the assumptive capacity of streams up to
2 a to be treated to NPEDS standards and than they 2 4 b1unt--it's otherwise harmful effect.
2 5 can be discharged into surface water. its 2 5 We very much wanttc encourage the use of
Page 71 Page ?33 3
1 controlled by the doparhusnt, but that 1 degraded sources ofwater and hydraulic
2 warrant the context ofthis delinitionwould 2 fracturing purpose, but weheliove that it is a
3 suddenly revert lacing deemed to be polluted 3 reasonablci?or the department to evaluate the 
4 water. 4 quality of these waters before basically we allow 3
5 So the ?rst element of this amendment 5 them to be stored and very regulated 
6 makes it clear that this water, ?ditch the 6 impoundmenls. We need to assume that these 
7 department allows to be discharged into streams 7? imp condiments are in fact actively that 
8 and lake and rivers, is not the sort of water 8 they areinhigh quality water sheds thatthe 
9 that is being considered in all of the 9 ground the water leaving thoseimpoundmeuts 
1 0 discossi one otherwise in the regulation about 1 0 has the potential to get into drinks water 
1 1 mice in?uence water. 11 supplies. So we need to hold a little bit of a
12 Also to help provide clarity to those in 12 higher standards to ?uid that are stored in
1 3 the public who are trying to conform with this 1 3 there when in fact we loaow that ?iey?rc ?iey i
1 4 regulation, the department is currently required 1 4 are polluted. 
15 Ithin has hiannually a maybe as 15 So we don'thelievcthatthis 3?
1 6 triannually to provide a integrated list of 1 6 a sound amendment to provide protection that 
7 all waters in the Commonwealth to EPA That list 1,7 reqsires during the hydraulic
1 8 is categorized and two of those categories deal 1 
19 with polluted surface waters and that will be 1 9 MR. QUIGLIEY: Rqatcsentative Mahor.
2 0 their list four and ?ve. 2 0 MR. MAKER: Mr. Chairman with your
2 1 So there is a concrete reference that ,e . 2 permission Imight. ask afollow up question 
2 2 people can look to if they're drawing water from 2 2 What is it about storing water that makes
2 3 category four or ?ve, theybetter be mindful of? 2 3 it dangerous if this Water is deemed safe enough 
2 4 this provision as opposed to having uncertainty 2 4 to heroleasedinto streams and rivers, why does
2 5 as to whether or not the water source involved is 2 5 Suddenly storing the water make it scary? It a
??i?cmm; - es - Wrens-deem. denser? ?m -- adv-ass? were. .- deem-J

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Page 7 4 Page "i 6
1 seems to me that if this water is scaly water, 1 is ifs water development pipeline is a temporary
2 the department wotddn?tbe permitting it so it 2 one, which is to serve for drilling a well, that
3 could be released into streams and rivers. 3 whenthat well is ?nished and that well site 
4 So perhaps you don?t have faith in the 4 the restoration at the end of drilling, that that
5 deparnnent?s permitting pron use with respect to 5 water development pipeline is to be removed.
6 mine water ireannent. I do, and I don't 6 If we this amendment would provide for
?i understand why you think simply storing this 7 exactly that. Without this amendment, you have
8 water makes it dangerous whereas if you release 8 an open ended time line that can go through tires
9 it into the rivers it?s okay. It makes no sense 9 that the well Is plugged, which could be 40 years
1 to me. 1 0 down the road. So this amendment is truly
11 MR. PERRY: What We are saying is that it 1 1 offered to make the regulation operative in a
12 should be evaluated so we can assure ourselves I 2 way that it's been described, and ihope that the
1 3 and others that if it. is in fact released in the 3 pride of authorship issues will not impair the
1 4 that it's not going to cause an 1 ability to make the regulation technically
1 5 impact, and} don't know ifyou?ve ever had the 1 5 precise.
1 6 pleasure of tubing down of yellow breaches when 1 6 MR, QUIGLIBY: I think actually
1 they are -- the discharge from the sewage 1 7 Representative you need to make a motion to amend
8 treatment plant is ongoinghut it?s really not 1 8 the rule to include the amendment.
1 9 necessarily something that you want to be bathing 9 MR. MAHER: i?m sorry, Mr. Chairmanmoved.
2 1 So just because something isheing treated 2 1 MIL QUIGLIEY: Is there a second? Second
2 2 under a permit and discharged, doesn?t mean that 2 2 by Richard. Onto question. Is there any
2 3 it is in fact as clean as the stream that is 2 3 questions? Richard.
2 4 receiving it. 2 4 MIL FOX: Was this amendment also suggested
2 5 So we think that we need to evaluate we 2 5 in the TAB report?
a go 7 5 Page 7 '7
1 want people to use this water. but it does raise 1 MR. MAHEIC My reoolleotiori is yes.
2 eonoems if it is not appropriately managed, and 2 MR. QUIGLIBY: John, do you have a
3 all we're asking here is the ability to evaluate 3 question?
4 whether it is clean enough that it can be stored 4 MR. ARWAY: I ask for the dep arnnent's
5 in a regulated fresh water imp condiment. 5 decision on the amendment.
6 MR. Any other questions on this 6 MIL QUIGLIEY: Scott
7 amendment? Allright. We will cull for avote 7 MR. PERRY: We did have debate about this
8 on RepresentativeMaher's Amendment No. 2. All 8 particular provision at discussions priorto even
9 those in favor of amending the original 9 this amendment beingprovided and as the
0 resolution to include this amendment please say, 1 0 representative has noted, we ?rmly believe that
1 ?Aye,? and by a show of hands please. All those 1 the rule as Mitten will not require temporary 
12 opposed? Motion fails. 12 pennanent lines to be subject to this provision.
1 3 You want to continue? 1 3 So we certainly don?t just don?t believe it?s
1 4 MR. MAKER: 3 would be dealutg with the 1 4 aneoessaiy amendment that will add valueto this
1 5 de?nition of well development pip eliue. To 1 5 rule.
1 6 tighten up the de?nition -- which I believe is 6 MR. QUIGLBEY: Other questions? All those
1 7 consistent with the what the department has 1 7 in favor of the motion to include RepresentatiVe
8 expressed their objective is has currently 1 8 Marisa Amendment No. 3 please say, "Aye? and
19 de?ned the reference to Chapter WAGS lacks the l. 9 raise your hands. 'lhose opposed? Motion fails.
2 0 sp eci?city to deal with the sine restoration at 2 0 MR. MAKER: l'd like to motion to consider
2d the conclusion of drilling. Without this 2 1 Amendment No. 4.
2 2 additional sp eci?oation, the Well. development 22 MR. QUIGLIEY: Is there a second? Seconded
23 pipeline would have a life open that would go 2 3 by But. Onto question.
2 4 well beyond the nature ?eets 2 4. MR. MAKER: Thanlryou, Mr. Chulnnan.
25 anticipated. Myunderstanding of the object here 2 5 Amendment No. 4 is two issues. One is that
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1 recognizing that the dwattment has provided in understand what the previous conditions looked i
2 Section 7865 ihat the restoration can be subject 2 like by looking to this right side of the site; 
3 to the desires of the landowner. 3 to the left side of the site, up slope and down 3'
4 For instance, what is upon that is created 4 slope to know how the land was altered during 3
5 for holding surface water at the end 0 when 5 well development, how clearly ifthe landowner 
6 the well is no longer in site, people might say, 6 is ?ne with that, We agree that they can sign
7 kind of like having thatpond. Let?s keep 7 off on it, provided it does not otherwise pose 
8 it. So the deparnnent has embraced that, and 8 potential ham.
9 said that owners of the land can melee decisions 9 And one of those areas other where a a
1 abouthow the land needs to be restored. I think 1 0 potential environmental harm may linger is with i
1 1 diets appropriate. 1 1 these large ?tcsh water hnpoimdnients. Ithink 
12 The regulation as draftedis internally 12 it?s one thing to allow in all cases sparking 
1 3 inconsistent on this point though. There?s a 3 lot, if you will, to remain but now when you?re g?
1 4 section which say that is landowners have this 1 4 talking about an impoundment that can store 
15 prerogative. It says as long as they?re 1 5 millions of gallons of water perched above 
1 6 complying with these other sections} which CL 6 someone else?s borne, Someone elsa's leoperty,
essentially, unless we make it clear it?s not 1 that may exhibit signs of slumping and the like,
1 8 to the owners prerogative, which will contradict 1 8 we ought to retain some authority to in fact 
1 9 it was. 1 9 require restoration because it?s imposing
2 0 So most of this amendment is to deal with 2 0 unreasonable enviromnental risk to be left in
2 1 that question, anintarnal consistency in ?re 2 1 it's current condition.
2 2 regulation 2 2 So we feel con?dent the rain as written
2 3 The second aspect of this amendment is 2 3 allowed reasonable choices when restoring sites.
2 4 recognizing for conventional wells; not for 2 4 We're not demanding ?rst the sites be restored to
2 5 unconventional, but for conventional wells. That 2 5 exact original centers but nearly 
Page 7 9 Page 8 
1 tons of thousands of these wells were drilled, 1 orgiginsl contours, which would be those that are
2 sited, decades and decades ago before anyone was 2 exhibited by the sites surrounding it and of
3 making records ofwhat the contours were before 3 course landowners consenting to that condition,
4 the well was there or what the conditions were a but we don?t believe that this is a sound choice
5 before the well was thereestablish a standard that requires 6 MR. Representative Mailer.
?l resonance to an unknown condition, an 7 MIL MAHEIC So I understand that you object
3 unknocrablc condition, my concernis this will 8 to providing the standard with conventional wells 
9 discourage operators from pursuing restoration, 9 to be if lmown, but are you also objecting to
1 0 because they will be asked to pursue a standard 1 0 clarifying where the landowners consent comes a
11 which is impossible to meet. No one knows. 1 1 into play? 2
12 So with respect to conventional wells, it 12 MEL PERRY: We have a section iniha a 
13 provides that the restoration to that original 1 3 Subsection in the section that speaks very
1 4 condition is if that condition is lmown and not 1 4 clearly to the landowner consent authorization. i
5 to hold people to an impossible unlmowable 1 5 IVER. AMER: It actually is the source of i
5 standard 1 6 the problem, Scott, because it refers to
MR. QUIGLEEY: Any questions? John. 1 compliance with Section A and Section 2 to 7, 
1 8 MR ARWAY: What the department?s position 1 8 and those sections are in order for the
1 9 on this arnendment?? 1 9 landowuer?s consent to be operative, it must
2 0 MR. QUEGLIBY: Scott. 2 comply ?so sections thi'? the land owner?s
2 1 MR. PERRY: We think ?rst addingthis 2 1 consent is not aolmowledged So you have this 5
2 2 section will actually create mores disputes 2 2 Catch 22.
2 3 between the department and drillers than it 2 3 This is jest drafting that if you're 3
2 4 resolves. 2 4 genuine in your interest that the landowner
2 5 When you go to Well site, you can clearly 2 5 should have this abilityto consent, I'm simply
anJump: um. rumFarm 
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1 asking that the wordsmithingin this dooumentbo 1 hazard. We do not needto be addressing that
2 consistent internally. It doesn't change 2 because after restoration, that
3 operatively anything. It just makes it clear 3 impoundment, as you call it, is what other people
4 ?aattho landowners consent is not obviated by 4 call a Hpond" or ?lake? but its subject as all
5 requiring that they confonnwith sections that 5 demo 
6 don?t allow for landowner consent. 6 MEL QUIGLEBY: Are there any other
7 I do not understand the pride of authorship 7 questions already the motion has been made and
8 being demonstrated where We can?t even have 8 second to amend the original motionto include
9 regulation tha?s internally consistent. It?s 9 Representative Mahler?s AmondmentNo. 4 please
1 0 very troubling. 0 say, ?Aye," and raise your hands. All those
1 1 MR. PERRY: Well, Representative, I think 1 1 opposed? Motion fails.
1 2 we disagree with your conclusion that it?s 12 MR. MAKER Mr. chairmen I would like to
1 3 internally inconsistent If you look at 1 3 propose Amendment No. 5, area of review and best
. 1 4 Subsection it says that the operator has to 1 4 area reqi?rement.
1 5 develop and implement a site restoration plan 1 5 MR. QUIGLIBY: You?ve made a motion; is
1 6 that complies with those sections not that the 6 that correct? YOumade emotion, Representative?
17 iandowncr has to comlywith those sections, and 17 MR. MAHBE: Yes.
1 8 frankly, there are concerns with storm water 1 8 MR. QUIGIIBY: Is there a second? Second
1 9 management that may remain behind even after the 1 9 by (ushrtolligible).
2 0 site is restored. Post-construction stormwater 2 0 MR. MAKER: Theolsyou, Mr. Chairman. The
2 1 management requirements may have to he motley the 2 1 area ofreview as pointed out in the departments
2 2 landowners as part ofthat consent. So it's not 2 2 presentation was something that conic up from
2 3 in fact something that -- we don't see that as 2 3 imagination in the department. It did not arise
2 4 being inconsistent. We think about it as coving 2 4 from status. It did not arise from BQB. I think
I 2 5 what needs to be covered. 2 5 that it?s not ahadidea. I do third: - in fact
Page 83_ Page 85
1 MR. MAEER. Think shots: what you just said. 3. I think it?s a good idea, but I think it's only a
2 You just said that than seco?on requires the 2 good idea if it?s a. reasonable standard.
3 operator that comply with these sections that do 3 To ask that operators identi?t drey
4 not provide for the landowners 4 shall identify things thatmaynot he
5 same section where it says that the landowners 5 identi?able is again presiding a standard that
6 consentwill be respected, but you, yountelf, 6 we did cannot reasonably expect to be most. So
7 pointed out that the operator is required to ?7 this amendment would introduce the standard that
8 disregard the landowners consent in order to 8 they must use their best efforts to identi?r
9 comply with those sections as written. This is 9 understanding that there are thousands of
1 0 ins: a matter ofgeth'ng this thing internally 1 abandoned wells that were abandoned long before I
1 1 consistent. 1 was is born ?rstsobody Imows where they are, and
1 2 MR. PERRY: I think we?rejust disagreeing 1 2 to require that someone identify eveqr well in an
13 with your interpretation ofthe role. There?s 13 18 note start that may have been there 50 years
1 4 clearly times when post?construction storm water 1 )1 ago or 1 00 years ago when ?lers is no intonnation
1 5 management focuses need to he maintained in 1 5 that would cause one to believe it's there seems
1 6 perpetuity, and a welt driller cannot wa?c away 1 6 to be an unreasonable standard, which would
17 from that responsibility by simply signing it essentially really impair the ability to harvest
1 8 to the landowner who himself now must agree 1 8 this resource.
1 9 to maintain these post?construction stem water 1 9 The second aspect of this is to provide a -
2 0 features throughout the life of the facility. So 2 0 bit of structure to the sources that must be
2 1 there is consent, but the landowner can't consent 2 1 considered. That the regulation as drafted
2 2 to creating an environmental impact 22 provides that the department?s well data base
2 3 MEL Well, on that point I would 2 3 should be used, and it says "The department's
2 4 observe thatwe have long established laws and 2 4 with well data base and other available well data
2 5 regulations that deal with dates that present a 2 5 bases." Well, if they?re available, I?m assuming
lilimi no- .. . - J- a? ?all?! hu- unmask i it. "m W1 moss: N=m "l -
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1 the department loiows So lwould hope 1 So it?s a bit of a soft standard. Utilize our
2 that the would have a list of these 2 data base, which does have the precise location
3 other available data basis. 3 of approidznateiy 9,000 of the maybe more than
4 ButI also recognize that some operators 4 250,000 abandoned wells inthe Commonwealth and
5 have been in the business a longtime 5 ask surface landowners who may have direct
6 have their own sources. So it?s very reasonable 6 knowledge of where abandon wells are located.
7 to hold them accountable to consuming their own 7 It?s our experience thatmany times that
8 archives and that's what this amendment would to, 8 wells that are in areas thatno one expected a
9 reqln're the best efforts of operators to do this 9 well to be were observed and have been drilled by
1 0 research usingidentitiable sources and their own 1 0 the individual residing there now. Boole in the
11 imowledge. 11 503 as a young child they saw them drilled a
12 MR. QUIGLIEY: Any questions? Iohn. 12 well. ?Iherc's no record of it modern, but they
1 3 MR. ARWAY: Does the department have an 3.3 leiow it's, because they warm there whenit
1 4 opinion? 1 1.1 happened.
1 5 MR. Scott. 15 So we believe that after extensive
1 5 MR. PERRY: The way this reeds would cause 1 6 consideration of all of the comments received on
1? Zthinlc an enormous cost increase for applying be 1 crafting the area ofreview we?ve done a
8 this porticx?er provision. Itrequires operators 3. 8 reasonable job of avoiding unnecessary expenses
1 9 to use best efforts to identify the surface and 1 9 of having people wall: the entire land. area where
2 0 bottom hole location of these wells and that 2 0 they might not have access to it, requiring
2 1 would of course mean entering the well to 2 invasive procedures likeosing best efforts to
2 2 physically log it. 2 2 idcoii? the bottom hole locations of wells and
2 3 We Were not going to require operators to 2 3 we thinkthat this amendment will create
2 :1 use best efforts to identify the bottom hole 2 4 ambiguity and is not necessary.
2 5 location of wells. Vertical wells were presumed 25 MR. QUIGLIEY: Any other questions?
Page 8 7 Page 8 9
1 that the bottom hole location would be the same 3. Richard?
2 as the surface hole location which may or. may 2 Mil. FOX: Not too much on the amendment,
3 not actually be true. we think that this 3 but since we're in this section, the term "fans
4 amendment doesn?t do what the representative 4 line maps." Can someone tell me what a "farm
5 reports it to do, but in fact creates more 5 line map" is?
6 ambiguity. 6 MR. PERRY: Yeah. Basically it's amore of
7 The issue of using other data bases and "i a historic map that was marked dating property
8 maps has actually been more contentious than bou salaries and frequently these old farm. line
9 other people realize. There?s been a fair 9 maps have locations of oil and gas wells on them.
10 amount of consideration ofthis particular 1 0 MR. FOX: Okay. Are they available at some
11 provision and discussion user it What we hoped 11 central location?
1 2 to do acmelly was have a single data base with 1 2 MR. PERRY: Operators have there, and they
1 3 all ofthe wells on it so that there would be a 13 refused to give them to us.
14 one stop shop and you wouldn?t: need to and 14 MR. FOX: Okay. Thank you.
1 5 another amendment to get rid of the landowner 5 MR. MAHER: I'm a little confused, Scott,
1 6 questionnaire. 1 6 by your analysis thatthis amendment would create
1 7 So we asked the industry to provide us with 7 the cost. The way that the regulation is drafted
1 8 all of their historic maps so we could digitize 1 8 right now it says the operator shall identi?r the
9 them and have this database so it could sche a 1 9 surface and bottom hole locations. What you
2 0 one stop shop. I foinkwe got a seven or eight 2 0 o??ered in your response is that?you aren?t
2 1 page legal brief of not givingus 2 1 really going to require the identification of
2 2 that elimination. . 2 2 bottom hole locations on vertical wells.
2 3 So woretained the language you?re not actually going to require it
2 4 include areview of applicable maps, because we 2 4 and if the reason that this amendment to say that
2 5 don?t lolow where they are all at or Who has them. 2 5 they need to use best efforts to identify it and
. sow-u? .. ..-.-.. - -- - - a. . wewummw hrs.? 4.. mm. seen. u. . 1: Jammie-4:4: .. - 
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1 the reason that you oppose that is because you 1 describing here today, and that's what we have
2 say it?s going to add it will 2 committed to doing. We've got that language
3 require them to identify bottom hole location 3 already together working with our conventional
4 that you?re not othemise going to require, if 4 and unconventional oil and gas advisory boards to
5 you?re not going to require it, why is it in this 5 ?nalize it. So I thinkthat we are adequately
6 regulation? 6 addressing the situation but certainly the
7 MR. PERRY: Well, the precise location of ?i amendment that you are proposing would be viewed
8 horizontalwolls, thatpathway does need to be 8 and objected to by the conventional industry.
9 identi?ed. 9 MR. QUTGIJEY: Questions? All in favor of
10 MR. MAHER: Right. That?s What the 1 0 Representative Muller?s motion to amend the tale
1 1 regulation says new. 1 1 to AmendmentNo, 5 please raise your hand and
12 MR. PERRY: Right. 1 2 say, ?Aye." Ali those opposed? Motion fails.
13 MIL So how does this amendment 1 3 MR. MEIER. Mr. Chairman, I would like to
1 4 increase cost? 1 4 introduce Amendment No. 6 dealing with 
15 MR. PERRY: When you use best effortto 15 MR. 15 there a second? Second
1 6 identify bottom hole iocations that means 1 6 byRichard
7 entering the 11. 1 7 MR, MAHER: in the notice of?nal
1 8 MR. MAHER: You think so? 1 rulcrnaking, the doparonent advises EQB and the
1 9 MR. PERRY: It's a best effort. 1 9 public that this subsection is not intended 
2 0 MR. MAKER: I see. That?s a humorous take. 20 using these Words, ?hotmtendod to establish any
2 1 Thank you. But when you say right now they shall 2 1 new requirements and therefore the deparonant
2 2 identify the bottom hole location, if I 22 attributes no cost to this section." The
2 3 understand your testimony correctly, you don't 2 3 department states that dress provisions, quote,
2 4 intend to require that? ?the regulation says 2 4 reiterate the requirements already
2 5 that, but you're not actually going to require 2 5 existing in Code Section 9134 and
Page 91 Page 93
1. that? 1 102.5."
2 MR. PERRY: We are assuming that vertical 2 This is considerabio discomfort in the
3 wells the bottom hole location is the same as the 3 regulated community that this, in fact, doesn?t
a seduce hole location. Obviously if there are 4 simply reiterate those sections. So this is a
5 records indicating -- if there are intentionaliy 5 technical mnendincnt in the Spirit of having the
6 deviated conventional wells tluoug?nout 6 regulation say exactly what the department says
7 obviously if there are records to 7 it intended to say in their notice of ?nal
reflect there?s an intentional deviation in the 8 ruletnaldng.
9 bottom hole location, that should be provided. 9 So if we don't adopt this amendment, I
1 0 MR. MAKER. So why don't you have the 1 0 would ask that the notice of ?nal rulemalo?ng be
1 1 regulation drafted to say what you're sa?ng you 1 1 revised to re?ect the change ?oats happening,
1 2 intended to do? 1 2 but if you're really intending this to be a
J. 3 MR. PERRY: The area that I think you're 1 3 reiteration of those code sections, well, that?s
1 4 taking issue with is simply our acknowledgemeit 1 4 exactly what the regulation should say.
1 5 that vertical wells, without records, will be 1 5 So I'm looking to have consistency between
1 6 presumed to have the same bottom hole location as 1 6 what the department says and the notice of ?nal
1 7 the top hole location. 1 7 ruienaldng and how the regulation is drafted.
18 MR. MAKER: Where is that in the 1 8 MR. QUIGLIEY: Onto question. John?
1 9 regulation? 1 9 MR. ARWAY: Does the department have a
2 MR. PERRY: It is not precisely stated in 2 0 position on this matter?
21 the rules. 2 1 MR. QUIGLDEY: Scott.
2 2 MR. MAHBR: It's not sated in it at all 22 MIL PERRY: Sure. The impetus for this
2 3 MR. PERRY: Many rules require additional 2 3 change is actually the precise language that?s
2 4 technical guidance documents to provide the lrind 2 4 proposed to be stricken out and that is the
2 5 of clarityto nuance situations that we're 2 5 prevention, preparedness, contingency plans need
. ass in . awocmW-r c: - W- mans?sternem e? - meant -. . -- - - amass.- r? -- - mm!
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25 (Pages Page 9 6 
1 to be site speci?c plans, and while that word 1 of regulation manuals, which hays not come 9
2 ?site speci?c" was not in factutilizcd in the 2 through the regulatory process. It's all well 
3 previous iteration of the rule, that?s precisely 3 and good to have manuals, but they don?t belong 
4 what was intended by that rule, but was 4 in the regulation. a
5 apparently not being followed. 5 So this would just simply strike the
6 So we needed to have greater clari?cation 6 reference for manuals and I?ll note that the i}
7 that when you are conducting oil and gas 7 department otherwise respected this hit of 
8 activities you need tohaveaptcvention, housekeeping through the drafting ofthis
9 preparedness contingency plan that actually 9 regulation, but did not in this single instance.
1 0 address the things that you're doing on that 1 0 MR. QUIGLDEY: Onto questions. John? 
l. 1 site. 11 MR. ARWAY: Does the department have a 
12 One of the easiest examples thatI l?ceto 12 position on this amendment? 9
1 3 use is that you have to have the identi?cation 1 3 MR. Scott; 
1 4 of~~ of the approp?ate hospital when someone 4 MIL FirstJ 1 Would like to note a
1 5 needs to go to the hospital, and avail witl?tin 5 that the same plan provision that we were a
6 there you got some hospitals that don?t 1 6 just discussing does contain a reference to a 3
1 "l neocssarilyhavo rattlesnake venom and some do. manual that if operators follow it it would be 
1 8 So a good idea to know which hospital is deemed to satisfy the requirotnents of that 
1 in your area has a rattlesnake antidote or 1 9 patticular section. 
2 0 antivenom if you?re going to be op crating in the 2 0 Erosion and sediment control issue are 
2 1 hills and woods of So ifyou have 2 1 really the number one problem at. both 
22 a PPC plan that says go to the Mercer County 2 2 conventional and unconventional sites. It?s a
2 3 Hospital and you?re in Tioga County, than it's 2 3 actually the number one cause of stream 3
2 4 not suf?cient plantalce it very 
2 5 So We mended it to be require that it he 2 5 seriously. 3
Page site speci?c, but many times a satire lease for 1 We believe it is helpful to simply 
2 conventional operations may not need to have a 2 reference the guidance that?s available to 
3 plan that varies at all, because it's all in the 3 operators so they can adequately address these 3
4 same area. They?re conducting their pads in the 4 issues. The language is not mandating that those it
5 same way. The wastes and ?uids they're storing 5 manuals are the only things that can be followed a
6 on site am being managed insame way. 6 in order to comply with the rule. It?s simply i
'7 So a, quote unquoto, "generic plan" can in fact '7 providing, what We believe, is the helpful cross i
a Work throughout We tried to make that clearin 8 reference to epdsting manuals and guidance ii
9 discussions with industry, but the impetus for 9 documents so the industry can adequately adjust . 
1 0 this change was in fact having it be site 1 this pervasive problem. l;
1 1 speci?c. 11 I'd also note that?iis previous a
12 So this amendment would basically undo the 3. 2 reference this has been part of the surface 
1 3 very purpose that we opened this section up for 3 activities rules, a reference to help?ti manuals, 
l. 4 change. 1 4 in this section for as long as I've been with the 
5 MR. QUIGLLEY: Other questions? Those in 15 agency and we believe it's a practice that ought g.
6 favor of Representative Maher's Amendment No. 6, 1 6 to continue. 3
please raise your hand and say, "Aye.? All those MR. QUIGLIEY: Other questions? if;
1 3 opposed? Motion falls. 1 8 MR. MAEER: Mr. Chah?man, I think it would 5
19 MR WEEK. Ammdment No. 7 I'd liketo 9 be good housekeeping to pursue the amendment, hut 
2 0 offer, Mr. chairman. 2 0 I?m going to just withdraw it, and I would like a
2 1 MR. QUIGLIEY: All right. Is there a 2 to suggest -- introduce Amendment No. 8 road 
2 2 second? Seconded by Richard. Please proceed. 2 2 Brine. 
23 MR. MAKER. Amendment 7 is a housekeeping 2 3 MR. QUIGLIEY: Is there a second? Second 
24 sort of amendment. Regulations in the normal 2 4 by Richard. Go ahead. 
2 5 course ofthings, do not elevate to the au?iority 2 5 MR. MAHER: I?m no fan of using brine on 
a
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the roads. I suppose I prefer it to ice, but. the
corrosive effect that it has on vehicles is quite
notahieto me in my many journeys across
So I?m glad that there are
restrictions about what sort ofbrine canbe
used. i didn't understand in the early days of
my awareness of this industry that this brine for
the most part is essentially sea Water. It?s

just sea water from an ancient ocean, which is
new buried, and some tunes liberated by drilling
and some times ?nds its own way out.

Whatl do wantto make apoint though is
that brine is being deemed as being aregulated
substance, and it seems to be we ought to be
saying, ?Ifit?s okay to put this thousands of
gallons at a time on our roadways, then itbetter
not be something that were considering otherwise
to be this terrible pollutant.? So I dorzt't think
that we can have it both ways.

If we?re going to call this apollutant or
we're going say it?s okay to put on the roads.

I prefer that we don?tput it onto the roads, but
the rcguistion is providing that we do, and we
have for years. I would just like to be clear
that what we're putting on the roads is not

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Page 100

protective.

So we wouid actually -- I think the heart
of this amendmeit wouldbe mandate that only
treatedbrine be utilized in the bene?cial way,
and we don't have the datato necessarily support
having that happen across the board

These numbers are in here for brine to be
used as a Clo-icing agent, because, quite frankly,
it needs to be very salty in order for it to be
effectively used as an anti-icing agent. Bribes
?ora most shallow oil Wells would probably
actually ?eeze on roads.

So there?s a -- that?s the reason why we
differentiated between the two, but nonetheless,
it would he consider to be a regulated substance,
but it would not he a violation of our rules if
utilized in the manner prescribed

MIL QUIGLIEY: Other questions? Rodger?

MR. COHEN: Secretary, Scott, lpresunle
from what you say that this regulatory language
has no lilnitingreach on the state or municipal
efforts to tie-ice roadways across the
Commonwealth?

MR. PERRY: No. In fact, the applicant for
this anth orization wouldbe Penn!) OT or the

 

 



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Page 99

something that we deem to be poison.

MR. QUIGLIEY: Onto questions. I ohn?

MR. ARWAY: Does the department have a
position on this amendment?

MIL QUIGLIBY: Scott?

MR. PERRY: The term ?regulated substance"
acutally applies to things well beyond
pollutants. So ifyou were to dtunp a truckload
ofinilk- on a ground, that mill: is new aregulated
substance. Rock salt to tie-ice roads is a
regulated stance.

We have considered this issue. Your
primary concern here is the utilization of brine
on roadways and this is a thinly
controversial Subject, because we don't, in fact,
require treated brine to be utilized as a dust
suppressant Un?eated brine has been utilized
throughout and other states as a
dust suppressant by municipalities for many, many
years. It has many constituents in it including
radium and heavy metals as well as organic
compounds, but the application rates and
prohibitions of applying it to roads with a
10 percent grade or greater or within 150 feet of
streams has itself to be environmentally

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Page 101

mmnoipal or if you had a parking lot, I suppose,
it wouldbe an individual, but by enlarge, the
aunties intending to use this are the
municipalities, To date, I don?t that anybody
has used brine as a deioing agent.

MR. COHEN: Okay.

MR. I should have also pointed out
that the amendment, recognizing that those who
are applying this brine, are municipal and state
employees. I ?nd it personally intrusive that
the employees names need to be listed, their home
address apparently, their phone numbers and the
license plates for these state and municipal
trucks.

Whoever is presiding this brine has got to
imagine what license plates will be on which
trucks at the time that the brine is applied to a
road, and it seems to me that thats a
Nostradamus sort of exercise that's a complete
waste of everybody time and oan?tteally be
?ll?lled, but it?s chatted here, and I'm
proposing that we at least get rid of the whole
license plate thing on municipal trucks.

MR, QUIGLIEY: Any other questions? All
those in favor of Amendment No. 8 please raise

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27 (Pages 102 to 105)
Page 102 Page 104 
1 your hand and say, "Ave.? r{those opposed? Motion 1 members of the industry and interested members of 
2 fails. Are there any other motions? Senator. 2 the public. So we can craft a guidance do sweet 
3 MR. YAW: Thank you. I have three 3 that threads that particular needle very 
4 amendments. Pd like to mova my amendment No. 1, 4 precisely. 
5 whichis clari?cation relating to the drinking 5 So the example that I?d use is thatyou?ve 
6 water standards. It's 7851132 and TEAS iB2. For 6 got an iron and manganeseproblem and you wanttc 3
those of you who read 7? ?x it by driliing someone a new water well and .1
8 MIL QUIGIIBY: Second? Richard. Ali 8 the new water well is ?ne for iron and manganese 
9 right. 9 but now you?ve got elevated levels bat-torn, 
0 MIL YAW: I'm sorry. For those of you who 1 0 strontium or chloride. I?d be concern that this 
11 red the TAB report dated January 16 and you want 1 1 language would now allow the operator to say, 
1 2 to refer to it. this address a question or 1 2 "Well, Eve my obligations even though 
13 problem which they raise on pages 4 and 5 of 1 3 the cure may have been worse than that impact,? a
1 4 their recommendation, and they that 1 4 but I certainly, Senator, I want to commit to you
15 this provision related to drinking water he 1 5 and others members ofthe board that. this concept 
1 6 revise-die provide a clearer standard. 1 6 oi'not fixingwhet you didn?tbreair and 
1 ?i So what I've done or what we?re l? iden?fyingmethods of restoring water supplies ii
1 8 proposing inthis amendment is that the drinking 1 with replacement supplies, such that homeowners 
1 9 water relating to oil and gas be identi?ed, the 9 aren'tleft worse off, is something that we?re 
2 0 parameters that we're talking about, be related 2 0 committed to working with stakeholders to devoiop 
2 1 to problems cause or parameters that testify by 2 1 the approPIi ate guidance for. 
2 2 the oil and gas industry and not something that 2 2 So I believe this amendment may cause 
2 3 Wouid be remote from that. 2 3 concerns for the down the road, but 3
24 MR. QUIGIJEY: Onto questions. 24 thatwe can certainly address the underlying i
2 5 MR. YAW: I'd like Mr. Perry?s opinionhl 25 impetus for your amendment to everyone's 
ii
Page 103 Page 105 
1 this. 1 satisfaction. 
2 MR. QUIGLDEY: Scott? 2 MR. YAW: My only comment is: Once again, i
3 MR. PERRY: We certainly agree that the 3 this is your recommendationby your own Technical 
4 parameters that need to be recti?ed in the cVent 4 Advisory Board. 
5 that water supply has been affected by oil and 5 MIL I agree, and I certainly wish 
6 gas activities -- they vv?ibe identi?ed by the 6 that we would here had an opportunity to more a
7 department and ?rstparamcters that are othenvise folly discuss it as wehad other issues 
8 elevated that were not caused by oil and gas 8 throughout the multi yoatprocess. ii
9 activities do not need to be ?xed during the 9 MR. QUIGUEY: Odicr questions? All those 
0 course of a water supply restoration. 1t} infavor of Senator Yaw?s AmendmentNo. 1, please .
1 So frequently we see individuals who have 1 raise your hands and say, ?Aye. Ali those 
1 2 total or focal colifonn in their water, which was 1 2 opposed? Motion fails. 
1 3 not obviously caused by and gas activities 1 3 WYAW: Ihave amendment 2. which is 
1 4 but elevations of iron or manganese or methane 1 4 amendment to and TEASSG, which is very
1 5 were. So we certainly agree that we would not be 1 5 simple. It attenuates the three day notice 
1 5 ordering operators to clean up the coiiform 1 6 requirement, and once again, for everybody that a
1 7 problem while they?re addressing the iron and 7 read the Technical Advisory Rep ort, which I?m 
1 8 manganese problem. 1 8 sure that everybody did, it's on page the concerns that we had with this 1 S3 ?atly says that we suggest that this language be 
2 0 language was that once We identi?ed the 2 removed relatcd to the three day notice 
2 permueters that need to be addressed, the . 2 1 provision. So that?s what the amendment dose. j_
2 2 solution can come in a variety ofways,? saddle - 2 2 It removes it. .3
2 3 solution cannot introduce new contaminant that 2 3 MR. QUIGLIEY: Ts there a second onthe i!
2 4 were not there otherwise. This is why we're 2 4 amendment? Richard. Onto questioning. Hearing 
2 5 forming a Work group with our advisory board and 2 5 none. All those in favor of Senator Yaw?s 
mac-sears" mmsmoanme?mm?oor. rm 'nmean' ?rm? are?;
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28 (Pages 106 to 109)
Page 106 Page 3.08 i
1 Amendment No. 2. please raise your hand and say J. a pounit for these itnpoundments, but we do i
2 ?Aye." Those opposed? Motion fails. 2 believe that they need to be constructed using 
3 MRYAW. My ?nal motion is Amendment No. 3 that resistbreachisg, and when We a
4 3, which would amend Sections 78169 and 59B 4 first met. with ?re Marcellus Shale Coalition to 
5 relating to iinpcundrnents and this is one that 5 talk about these kinds of issues we had already 
6 restoring the amendment restores the fresh 6 developed a fact sheet on best practices for I
'1 Water impoundment classi?cation, and this is one '3 developing fresh water irnpoundmonts, which have
8 that -- wait. We probably need a second. 8 been incorporated into the rule, and they thought .
9 MR. Is there a second? 9 that they Were always required to do that. a
re ran FOX: Yes. to Solthinkthereason whywehaven?t herds 
1 1 MR YAW: Sony. 11 catastrophic failure -- and when one of these
12 MR. That?s okay. Thanh: you. 12 things catastrophic tails, it's going MYAW: New, this is one where the storing 1 3 minimum, damaged property ifnot potentially 
1 4 of fresh water would not have to meet the some 14 serious injure someone. It could flood a
15 standards of open water areas where, for example, 15 roadway. It could wash out soinecne's house. I a
1 6 there was residual waste, and this is one where 1 6 thinltheoause the industry was already following i
1 7 when I questioned the DEP about it, they said 1 ?l ?rese heightened embanlonent construction 
1 8 that they never had a situation involving fresh 1 8 standards, that?s probably why we have not had 
1 9 water Where it had never been a problem. 1 9 necessarily an;r catastrophic failures, and
2 0 So this is one of those compelling interest 2 0 personally, I think the departments perspective 3
2 1 that I have. There?s never been a 2 1 is we do not want to wait for thereto he a i
2 2 problem Why are we ?xing it? 2 2 catastrophic failure of one of these hupoundtnonts 3
2 3 MR. Onto questions. John? 2 3 before -- when we know we can take reasonable i
2 ?1 MR. ARWAY: Is does the department have a 2 4 steps to act. 3
2 5 position on the amendment? 2 5 Again, we?re not requiring a pcnnit. So i
Page 10'? Page 109 
1 MR. QUIGLIEY: Scott 1 we're not slowing down the construction process. i
2 MR. PERRY: Sure. The scope of this rule 2 We?re the industry build these 3
3 applies to fresh water hnpoundments which 3 cmhankments to a sound engineering standard. 3
4 historically under our Dam Safety and 4 A. VOICE: Existing impoundments do not have 
5 Encroachment Act is if you imp co ndtnent stored 5 a retroactive effect? Okay. Thank you -
6 less than l5 acre feet of water and was shallower 6 MR. QUIGIIEY: Any other questions? All
7 than 15 feet deep, itwas notregulatcd, and the 7 those in favor of SenatorYaw's Amendment No. 3 .
3 unique aspect of oil and gas development, shale 8 say, ?Aye," Those opposed? Motionfails. 5
9 gas development, called to quostion the 9 Are there any other motions? Richard. 1:
1 0 appropriateness of that decision. So you?re 1 0 MR. FOX: On behalf of 
1 taking shoot hnpoundments that can store 16 1 1 {have ?vo amendments that I believe have been a
1 2 million gallons of water. 1 2 distributed to everybody cl?rer electronically or a
3 And unh?ke traditional impoundmonts that 1 3 hard copies, and i'd like to take them one by a
1 4 storelarge volumes of?'csh water, its not 1 4 one. a
1 5 actually located on a stream or employing, like, 15 My ?rstmotionis to amend or have 
1 5 a valley, say, to impound the ?uids. You're 1 6 amendment No. to amend chapter 78 and 78A.
1 7 taking these facilities and putting them on top 17 MR. QUIGIIBY: A second?
1 8 of hills, above people?s homes or at any 1 8 MR. YAW: Second. 3
1 9 location. So it?s unlike any other industry in 9 MR. QUIGIIEY: Senator Yaw. Please
2 0 No one goes and builds 2 0 proceed. a
. 2 muitimillion gallon ponds out in the middle of 2 1 MR. FOX: This ?rst amendment brings to 
22 nowhere that can't be replenished with streams 2 2 language in 78.51 and 78.251, protection water ii
2 3 and the like. 2 3 supplies to be consistent in 3:
2 4 So we had concerns about the 2 4 Act 13. Act 13 uses the language "drilling, i
2 5 themselves. Now, we?re not proposing to require 2 5 alteration or operation of a we as opposed to a

mum..- s. mean.- mm: . -- warm mg. ?Wear-m? we: - .
Morse Gantverg Hodge
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Page 110 Page 112
1 ?oil and gas operations." 1 construction. That?s whei'eI would say that
2 MR. QUIGLIEY: Onto questions. John?? 2 Icrossed the line.
3 MR. ARWAY: Does the dcpalhnent have a 3 MR. QUIGUBY: Other questions? All those
4 position on the amendment? 4 in faces of Senior Yudichak?s Amendment No. 1
5 MR. PERRY: The department proposed to 5 please raise yourhaud and say "Aye.? Those
6 amend this particular section because of our long 6 opposad? Motion fails.
7 standing practice of requiring water supplies 7 MR, FOX: Okay. Mr. Chairman, my second
8 that are affectedby something other than oil and 8 amendment, AmeldmentNo. 2, Imovothstit amends
9 gas drilling or alteration tobe restored or 9 Chapter 78 and 73A 1 think to at least clarify
1 0 replaced We have had water supplied that have i 0 when some information is supposed to beprovided
11 been aifectedhy pad construction. Particularly, 11 by the depatbnent.
12 folks -- diere's a ofpeoplcio 12 MR. Second?
13 that actually use springs as awater 13 hm. YAW: Second.
14 Supply, and pad construction can disrupt that and 1 4 MR. QUIGLIJBY: Chilli-
15 cause pollution. 15 MR. FOX: 'Ihaok you, Mr: Cincinnati. I seek
6 We?ve had water supplies a?ected by 1 6 a literalroadiog ofthat section would say that
1 7 horizontal directional drilling where they?re 1 7 the fonns provided though its website ten
1 8 putting pipe under streams and the beetonite mod 1 8 business days prior to Icotdpt of all samples
1 9 gets into the aquifer and plugs up water Supplies 1 9 that the form would have to he received on the
2 0 affected by mismanagement of waste and through 2 0 tenth day, not the eighth day, not the seventh
2 1 the simple act of drilling, and the statute 2 1 day, not the eleventh day. So with the change it
2 2 itself really speaks to water supplies than are 22 to say "atleast ten business days prior to."
2 3 affected by drilling alteration or operation of 23 MR. QUIGZIEY: On the questions. John?
2 4 the well. 24 MR. ARWAY: What's the depmnnent?s
2 5 And while we know that the presumption of 2 5 position on that?
Page 111 Page 113
1 liability does not apply to these other 1 MIL QUIGIIEY: Scott?
2 activities, it does only apply to drilling 2 MR. PERRY: Well, I haveto admit that we
3 alteration and operation, we felt that there was 3 used the term at least in other section of the
4 a compelling public need to clearly infonn the 4 rule. We did not use it here. Obviously the
5 operators and the public what our expectations 5 precise noti?cation language that occurs
6 are with respectto restoring and replacing water 6 throughout Chapter Act 13 does not have this
7 supplies. if any of your activities pollute a 3' word "at least" in front of it, and the
8 water supply, we will require it to be restored 8 department has always told operators, ?You can
9 orreplacodby the standards speci?ed by Act 13, 9 tell us" ?You have to tell as you're going to
1 0 but We were also clear that the presumption of 1 0 spud the well 24 hours prior to die action," and
1 1 liability did not apply to those ancillary 1 1 they could tell no that they?re going to spud the
12 activities. So rather than engaging in 12 well next February 3rd today.
it 3 protracted debates or disputes with operators who 1 3 While this amendment certainly adds
1 4 have affected thewatcr supply by smoothing other 1 4 clarity, We don't believe it?s actually
1 5 than d?llings, We felt that it was necessary to 5 necessary, because this is how we implement the
1 6 include this intherules so it's clear 1 5 program today. We allow operators to give us
1 7 what our expectations are. 1 7 notice whenever they Want as long as it is before
1 8 MR. QUIGLIEY: Any other questions? 1 8 this too day out oit?. So ?mdamentally We don't
1 9 MIL FOX: Do you feel that?s an expansion 1 9 believethat adding this language will not change
2 0 of what the statute says? 2 0 how the program is implemented.
2 1 MR. PERRY: The Clean Streams Law is 2 1 MR. QUIGIJEY: Allthose in favor of
2 2 protective of all waters of the 2 2 Senator Yudichalt's Amendment No. 2 please raise
2 3 including ground water. So that it would 2 3 your hands and say "Aye." All those opposed?
2 a clearlybe an expansion, Richard, ifwe said that 2 4 Motion fails.
2 5 you are presumed to have caused this by your pad 2 5 MIL FOX: Mr. Chairman, Ihavc a third
:11. . . cams?eh we} . "um: i ti 1. w; Men. -. 2' 531m- seat .4. . - . 
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30 (Pages lid to 117)
Page 114 I Page 116 
1 amendment I?d like to offer is an amendment 1 cards, ifycu will, and we further expanded the 
2 that?s beenbrought up in a TAB report that's 2 de?nition of certi?ed mail to be any verified 
3 been mentioned several times and in regards to 3 means. So they oanuse UPS or Fed Ex or sheritf 
4 the questionnaire rcquiredunder the area of 4 I guess. So it's beyond that. Kurt, wordd you it
5 review. So I'd liheto move so discuss this 5 mind describing we will soon have all of the 5
6 amendment. 6 forms that people have been about 
?7 MR. QUIGIJEY: Senator Yaw seconds. Go 7 available for our advisory committees review. 
8 ahead. 8 I lmow, Kurt, you?ve seen this particular 2
9 MR. FOX: comments. Chairman. Asthe 9 questionnaire Would you minddescrihingit?
1 0 TAB report noted there?s a lot of questions 10 MR. MPKOWSKI: Sure. With most of the
1 1 regarding this questionnaire that the operators 1 1 forms under the regulation, it?s pretty much a 
1 2 is supposed to submit by certi?ed mail to the 12 direct driver out of the regulation. So the
1 3 landowner, ?Iherc?s no discussion once that 13 regulation sets the standard. They?re required 3
14 operator does not get equestionnairc back. He's 14 toprovide the questionnairetc the landowners i
1 5 then responsible for any absence of information. 1 5 asking them if they have any imowledge of old a
6 There's no forms provided and as TAB suggested, 1 6 abandoned orphan wells on their property and a
1 3' this amendment removes that requirement of 1 '7 locational informedonto the extent that they?re ..
1 8 submitting a questionnaire to the land owner. and 1. 8 able to give to the operator and the condition of a
3. 9 providing proof to the deparhnentthet duct 1 9 the well to the extent that they have any 
2 0 information was or a. questionnaire was 2 0 understanding ofthat, and they may not 
2 1 51113de to the landowner. We don?t know what 2 necessarily have that. 
2 2 the questionnaire is supposed to look like and 22 And the Way that theregula?on is 
2 3 what the process is. So that's what this 2 3 structured is that the operator doesn?t necessary 
2 4 amendment docs, following up on suggestion or 2 4 need to provide to that questionnaire 
25 reactomendntionby TAB. . 25 to the department. It's justwhen tlleysubmit 
Page 13.5 Page 117 
1 MR. QIHGLIBY: Onto question. John? 1 their is survey report, theywill iden??f, "This 
2 MR. ARWAY: Does the department have s. 2 well was identi?ed as part of a landowner
3 position on the 3 questionnaire. This well was identi?ed as part 
4 LEE. QUIGLJEY: Scott? 4 ofthc operators actually walking an area and 
5 MR. PERRY: We actually believe that 5 there's actual locationalinfonnation to that." i
6 landowners may be perhaps the best source of 6 So then we can populate our data basis, and i
7 information for wells on their property. Again, '7 there's some context given to that locational 
8 we attempted to get - we wanted to address this 8 information so when someone looks at that data
9 a different fashion, in. a simpler fashion, by 9 base they know that someone actually stood at 
1 0 having well locations be made available on the 1 0 that site with a GPS unit and tookthe location i
1 department's databasewas merely horn alaodowner that that?s 
1 2 . kind ofcooperstion that I really expect that we 1 2 where that well was. a
1 3 would have. 1 3 So it?s actually relativelyr straight? 
1 4 So we really believe strongly that 14 forward and gets to some of the questions about .
15 utilizing this questionnaire is even; affection 15 the forms and guidance under this wiemaldng. 
1 6 way of finding out about wells that there maybe 1 6 Obviously, until the rulehed certainty atthe a
17 no records of. 17 certain Icvciit?s dif?cult to draft what the
1 8 The process that we have outlined in no 1 8 form Would look like or what the guidance
1 9 different than the process or legislature 1 9 document would address, but I third; this area in I
2 0 prescribed as part-of the process 2 0 a particular is one that! guidance 
21 that water supplies and landowners within the 2 1 document developmentprocess has been ongoing 
22 prescribed distance must twelve an actual copy 2 2 with Wollc groups since late last year, I guess 
2 3 of the plat by codi?ed mailDecember or maybe late November oflast year, and a
2 4 not asking for - unlike the well peonit, we're 2 4 I think that the work product that?s going to g.
2 5 not even asking them to provide all of the green 2 5 come out of that group and that technical fad
-- we - .- Imd?aL?W -- re - mm? Jag-ems;- a; - mam - oar:
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Page 118 Page 120
1 guidance: document and those forms are going to be 1 transparency is a the manner in which these
2 at the highest level that the department could 2 wastes are managed, and the times that we?ve gone
3 generate. 3 in and evaluated these reports we found
4 MR. QUIGHETY: Other questions? All those 4 considerable errors. So this is self~reporting
5 in favor of Senator Yudichalr?s Amendment No. 3, 5 waste managmnent?latl know thatthepnhlic has
6 please raise your hand and say ?Aye." Those 6 a lot of questions about. They do not believe
7 opposed? Motion fails. the veracity of these report and the story that
8 MIL FOX: Mr. Chairman, lmove Amendment 8 the department can?t necessary substantiate the
9 No. 4 in the packet which amends section 78A.12L 9 claims is all being managed appropriately,
1 0 MR. QUTGEIEY: Secondedby SenatorYaw. 1 0 because the review will be done already has
11 MEL FOX: Thanlcyoo. Ihis amendment 11 indicated fairly high error rate.
12 touches on the reporting of waste materials. I 3. 2 So we think that we need to be much more
1 3 know that Scott touched on this in his 13 the diligent in our review of these records, and
4 presentation about requiring reports for 1 4 it needs so be done more timely so we don't have
1 5 waste materials. The amendment would change the 15 six months or a year go bye of
1 6 reporting to event six months. I think tooqu 1 6 gallons of waste Water are unaccounted for.
1 7 is a little onerous. We?re all everybody here 1 7 MR. KLAPKOWSKI: Scott, coal make upoint?i'
18 is howwe?re drowning in papers or emails until 1 8 in response to your comment, Mr. Fox, the 
1 9 bellow, that other waste streams are not reported :1 9 department already has a production of electronic
2 0 on hazardous waste, municipal 2 0 waste reporting system in place. In fact, we?ve
2 1 solid waste, and if anything, theytre reported 2 1 built the capability to receive these reports on
2 2 quarterly, and I think that it?we report it notice 22 a basis, and some operators can
2 3 a year, it would give the operators time to 2 3 voluntarily socially do the reports now
2 4 submit more accurate iufcnnationand are doing the reports now. So I
2 5 think if the department actually -- if there was 2 5 think your concern about the volumes of paper
Page 119 Page 121
1 a problem and they need information, they could 1 being generated, we?ve already addressed that
2 always go to an operator and request it. So this 2 issue, becauscit?s going to be afully
3 just changes the reporting to every six months 3 electronically reported system that?s going to be
4 instead of 4 publicly available as the data updates every
5 MR. QUIGLIEY: Onto questions. All those 5 month.
6 infavor of Senator Yudichalt?s No. 4 5 MR. QUIGLIBY: Other questions? Allthose
3? please raise your band and say "Aye. 7 in favor of Senator Yodichalt?s No. 4,
8 MR. FOX: Scott, am I correct in saying 8 please raise your hand and say, ?Aye." Those
9 that other waste streams are reported less 9 opposed? Motion falls
1 frequently? 1 0 MR. FOX: Ifl can keep my record going,
11 MR 3ERRY: Certainly hazardous waste is 1 AmendmentNo. 5 amends the order on page 1.
1 2 tracked much more rigorously udth an social 1 2 MR. QUIGLIBY: Senator Yaw seconds.
1 3 manifest and it?s actually one of the many 13 MR. FOX: Very simply the amendment would
4 comments that we received on this particular 14 change ?le affective date of the 180
1 5 subj act is that we should require a 15 days after public ation of the 
1. 6 manifestation, and I believe that Ohio is 6 Bulletin. Essentially when they these rules are
1 '7 considering that now: the most extensive ruleinalcing the dopament has
1 Our concern, ttanldy, is that ifwe're 1 8 had probably in over a decade. I applicate the
1 9 going to do a manifest, it needs to be done 1 9 work, as Scott said at the beginning, of
2 electronically because having 108,000 pisses of 2 hard work.
2 1 paper, you know, you get the pink one, you get 2 3. When they getpublished on a Friday
2 2 the yellow one, and he keeps the white one is not 2 2 electronically and Saturday ahard copy. they're
23 a way ?rst the department should operate any 2 3 in effect for the industry. We've all heard the
2 4 longer, but we have identified, and ?iepublic 2 4 discussion today abouthow many forms, technical
2 5 has identi?ed7 a public need here for greater 2 5 guidance documents have to be developed and
?u 13:. um {m e. - Jags: moms-newsH.517. ?Wm-5'3! ?lg

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Page 1.22 Page 124
1 things have to be worked out. 1 not: six months 1 Quality Board members to do their responsibility.
2 matession would allow operators hidiis 2 That should never be the case.
3 departmentto ?nalize forms, guidance documents 3 lcortainly don?t feel like 1 had apart in
4 and train ?eld staff and have training for the 4 formulating these regulations. I don't know how
5 industry so that there?s a smooth transition to 5 you can look in the mirrors and think that you
6 these new regulations. 6 did as members of the EQB.
7 MR. QUIGLIEY: Any questions? John. 7 When. we see something as simple as a typo
8 MR. ARWAY: Does the deparnnent have an 8 correction or the common sense of saying a
9 opinion? 9 negt?ation should say something should have to
10 MR. QUIGLZEY: Yes, I can handle it. Work 10 arrive in the mail on a date certain, atleost
1 1 on this package began almost five years ago. 11 that many days ahead, when we see that that's
1 2 We?ve gone through the unprecedented, transparent 1 2 objected to, have to just shake my head. Whore
3.3 public process. This rule has obviously has been 1 3 is the common sense?
1 4 well scrutinized It?s time to ?nish the job, 1 4 Wehad an I wasnt part of on board
1 5 and to put ?dress reasonably balanced and 1 5 when the original mlemalcing was published, but I
1 6 incremental protections for public health and the 6 am aware that the information required be
1? environment into affect. We are opposed. 1 7 to 3312me not provided. EEK certainly
3. 8 Any other'qnestions. All those in favor of 8 corresponded to that effect Some of that
1 9 Senator Yodichalds Amendment No. 5 please raise 1 9 information still does not exist.
2 0 your hand and say, ?Aye.? Those opposed? The 2 0 We know that before we consider mics and
2 motion fails. 2 1 regulations we're required under the Regulatory
2 2 Are there any other motions? Seeing none. 2 2 Review Act to have to forms associated or
2 3 The motion before us is the original one, the 2 3 inferred to by those regulations available, not
2 4 motion to approve - by this board to approve 24 just for our purposes but for the public. Those
2 5 Chapter 78 and Chapter 78A final 2 5 forms aren't here. We're hearing thatthefre
Page 123 Page 125
I MR. MAHER: Onto questions? 1 going to be developed. Yonire being 
2 MR. QUIGLIEY: Onto question. 2 ignore your statutory duty to break the law about
3 MR. MAKER. Those of us around this large 3 how regulations are mitten and adopted.
4 table are either members of the Enxo?romnental 4 The governor could appoint anybody with ?re
5 Quality Board or alternates for members. In 5 appropriate quali?cations of the Technical
6 either case, the Environmental Quality Board is 6 Advisory Board, and he appointed people. Their
7 the entity that has the statutory authority alone 7 recommendations in the document - very thought
8 to formulate and proml? gate regs] stions ?rst deal 8 full document, disregarded the governor created
9 with the 9 with conjunction with the chairman. The
1 0 Now, as apractioel matter, there's 1 0 Conventional Oil and Gas Committee, they chose
11 certainly departments often it?s DEF, 1 1 who the}r wanted committee the
12 sometimes it?s other departments who 12 governor?s appointee again their droughts
3. 3 essentially staff that undertakingdisregarded.
14 their undertaking. It is the underteldng and the 1 We hear today in explanations about some of
1 5 responsibility ofthc members ofthis board 15 those proposed amendments to the regulation the
1 6 In the instance of this regulation, while 1 6 answer is, ?We?re not really going to do what the
1 ?l the chairman says unprecedented transparency, I l? regulation says. We're going to do something
1 8 will remind members of this board that in 1 8 else." Is that transparent? Don't wehave a
1 9 conjunction with our responsibilities speci?c to 1 9 duty to the public that What's published as a
2 0 this regulation, I asked during a BQB meeting 2 regulation is something that they should be able
2 1 last year for simply having information provided 2 1 to pick up and understand and not have to depend
2 2 to board members relevant to the regulation. The 2 2 on some insider grapevine that, ?Oh, well, if you
2 3 cheinnen declined. So not only are we has our 2 3 know so?and?so, just talk to him, bcomlse they
2 4 sta?" not been transparent, it has in fact 2 4 don?t really follow the rule." We should never
2 5 obstructed the ability oftho Environmental 2 5 be adopting regulations when we?re hearing from
I nil?! ".17 5: .J. manna: ?hissed :nr Mmr? - . 
Morse Gantverg Hodge

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Petition - Ex. 

 

6431

RULES AND REGULATIONS I

Title 
PROTECTION

ENVIRONMENTAL QUALITY BOARD
[25 PA. CODE CHS. 78 AND 78a]

Environmental Protection Performance Standards
at Oil and Gas Well Sites

The Environmental Quality Board (Board) amends
Chapter 78 (relating to oil and gas wells) and adds
Chapter 78a (relating to unconventional wells) to read as
set forth in Annex A. This ?nal-form rulemaking relates
to surface activities associated with the development of
unconventional wells. The goal of this ?nal-form rule-
making is to set performance standards for surface
activities associated with the development of unconven-
tional wells and to prevent and minimize spills and
releases to the environment to ensure protection of the
waters of the Commonwealth, public health and safety,
and the environment.

This ?nal?form rulemaking represents the ?rst update
to rules governing surface activities associated with the
development of unconventional wells. This ?nal-form
rulemaking adds Chapter 78a to establish the require-
ments for unconventional well development and amends
Chapter 78 to delete any con?icting requirements that
remained in that chapter for unconventional wells.

Major areas of this ?nal?form rulemalring in Chapter
78a include public resource impact screening, water sup?
ply replacement standards, waste management and dis-
posal, and establishing identi?cation and select monitor~
ing of wells located proximal to hydraulic fracturing
activities. Other new regulations include standards for
well development impoundments, a process for the closure
or waste permitting for wastewater impoundments, onsite
wastewater processing, site restoration, standards for
borrow pits, and reporting and remediating spills and
releases.

Chapter 78a also contains requirements for the contain-
ment of regulated substances, oil and gas gathering
pipelines, well development pipelines and water manage-
ment plans (WMP).

On February 3, 2016, the Board adopted the pre?Act 52
regulations containing two separate chapterse?one for
conventional oiland gas wells (Chapter 7 8) and the other
for unconventional wells (Chapter 78a).

The Department of Environmental Protection (Depart-
ment) delivered the pro-Act 52 ?nalnform regulations to
and the House and Senate Environmental Re-
sources and Energy Committees on March 3, 2016. On
April 12, 2016, the House and Senate Environmental
Resources and Energy Committees voted to disapprove
the pro-Act 52 ?nal?form regulations and noti?ed IRRC
and the Board. On April 21, 2016, IRRC held a public
hearing to consider the pre?Act 52 ?nal?form regulations
and approved it in a 3-2 vote. On May 8, 2016, the House
Environmental Resources and Energy Committee voted to
report a concurrent resolution to disapprove the pro-Act
52 ?nal-form regulations approved by IRRC to the Gen?
eral Assembly. rl?he concurrent resolution was not passed
by the General Assembly within 30 calendar days or 10
legislative days from the reporting of the concurrent
resolution.

The act of June 23, 2016 (PL. 879, No. 52 (Act 52))
abrogated the pro?Act 52 {inalnform regulations ?insofar
as such regulations pertain to conventional oil and gas
Wells.?

The Department delivered the pro?Act 52 ?nal~form
regulations to the Of?ce of Attorney General for form and
legality review on June 27, 2016. In accordance with the
Regulatory Review Act (71 RS. 7 451?74514) and the
Commonwealth Attorneys Act (71 ES. 732-101_732-
506), the Of?ce of Attorney General directed the Depart?
ment to make changes to the pro-Act 52 ?nal?form
regulations to comply with Act 52. Speci?cally, the Office
of Attorney General directed the Department to comply
with Act 52 by removing all amendments or additions to
the ?nal-form regulations in Chapter 78 regarding con?
ventional oil and gas wells prior to resubmission to the
Of?ce of Attorney General for review. Additionally, the
Of?ce of Attorney General directed the Department to
retain all deletions and modi?cations within the preuAct
52 ?nal-form regulations of Chapter 78 that related to the
unconventional oil and gas industry and to ensure that
the requirements in the ?nal?form rulemaking in Chapter
78a supersede any con?icting requirements in Chapter
78. The Of?ce of Attorney General also objected to several
typographical errors and sought corrections and clari?ca?
tions to the following provisions: the de?nition of ?mine
in?uenced water? in 78a.1 (relating to de?nitions) and


and 78a.91(a) and
78a.101.

On July 26, 2016, the Department resubmitted this
?nal-form rulemaking to the Office of Attorney General
for review. In accordance with the Of?ce of Attorney
General?s direction, the Department removed all amend?
ments or additions to Chapter 78 regarding conventional
oil and gas wells and retained the deletions and modi?ca-
tions in Chapter 7 8 that related solely to the unconven~
tional wells. This revised ?nal?form rulemaking also
contains clari?cations and corrections to respond to other
issues identi?ed by the Of?ce of Attorney General, includw
ing the addition of 78a.2 (relating to applicability) to
clari?r that Chapter 78a supersedes Chapter 78 for
unconventional wells to avoid any potential con?ict be-
tween the requirements in Chapter 78 and Chapter 78a
regarding unconventional wells. Later on July 26, 2016,
the Office of Attorney General approved this revised
?nal?form rulemaking for form and legality under the
Commonwealth Attorneys Act. The ?nal?form rulemaldng
in Annex A is the revised ?nal?form rulemakiug as
approved by the Of?ce of Attorney General. This pre-
amble was revised to re?ect the ?ua1~form milemaking as
approved by the of Attorney General in confor?
mance with Act 52.

The Joint Committee on Documents met on August 18,
2016, and voted to direct the Legislative Reference Bu?
reau (Bureau) to publish this ?nal-form rulemaking.

A. E?cective Date

This final-?form rulemaliing will be effective upon publi?
cation in the Bulletin.
B. Contact Persons

For further information, contact Kurt Klapkowski, Di-
rector, Bureau of Oil and Gas Planning and Program
Management, Rachel Carson State Of?ce Building, 15th

BULLETIN, VOL. 46, NO. 41, OCTOBER 8, 2016

 

6446 RULES AND REGULATIONS

tion, as well as Federal agencies. For example, the
Department of Conservation and Natural Resources is
required by statute to manage State parks and State
forests, as well as to survey and maintain an inventory of
ecological resources of the Commonwealth. Similarly, the
Fish and Boat Commission and the Game Commission
have responsibility for managing various ?sh and wildlife
resources within this Commonwealth. Federal agencies
also have jurisdiction over certain water resources, as
well as Federally protected ?sh and wildlife resources.
Further, public resources agencies have particular knowl-
edge and expertise concerning the public resources they
are reaponsible for managing.

Section 78a.15(f) establishes a straightforward process
for well applicants to notify public resources agencies and
provide those public resources agencies the opportunity to
submit comments to the Department on functions and
uses of the applicable public resources and any mitigation
measures recommended to avoid, minimize or otherwise
mitigate probable harmful impacts.

By requiring the applicant and the Department to
consider recommendations from public resource agencies,
this ?nal-form rulemaln'ng ensures that the Department
meets its constitutional and statutory obligations to con?
sider public resources when making determinations on
well permits. Importantly, these provisions function to
provide the Department with information necessary to
enable the Department to conduct its evaluation of the
potential impacts, to review the information in the con?
text of the criteria in 78a.15(g) and to determine
whether permit conditions are necessary to prevent a
probable harmful impact.

Public resources to be considered in. 78o.15(f)

A related set of comments concerned the list of public
resources that trigger the impact screening process, with
the thrust of the comments being that the list was too
narrowly drawn and should be expanded to include other
resources. Other commentators argued that the list of
public resources does not mirror what is in the statute
and therefore should be narrowed.

Under section 3215(c) of the 2012 Oil and Gas Act, the
Department has the obligation to consider the impacts of
a proposed well on public resources ?including, but not
limited to? certain enumerated resources when making a
determination on a well permit. Accordingly, given the
authority in section 8215(c) of the 2012 Oil and Gas Act
as well as the Department?s constitutional and statutory
obligations to protect public resources, the Department
has the authority to expand the list of public resources to
include public resources similar to those listed.

Section of this ?nal?form rulemaking in-
cludes the public resources listed in section 3215(c) of the
2012 Oil and Gas Act. Based on comments received,
?common areas of a school?s property,? ?playgrounds? and
?wellhead protection areas? were added because these
resources are similar in nature to the other listed public
resources. Playgrounds and school common areas are
frequently used by the public for outdoor recreation,
similar to parks. Wellhead protection areas are associated
with sources used for public drinking supplies, another
listed resource. In further response to comments, the
?wellhead protection area? public resource has been clari?
?ed by including a cross?reference to 109.713 (relating
to wellhead protection program) and limiting the areas to
those classi?ed as zones 1 and 2. Additionally, de?nitions
of ?common areas of a school?s property? and ?playground?
have been added to 78a.1.

Notwithstanding the enumeration of speci?c public
resources in this ?nal-tbrm rulemaking, the Department
will consider the potential impacts to other public re?
sources identi?ed during the permitting process.

To the extent that commentators questioned what
constitutes an impact, and (8) outlines the
process for coordinating with public resource agencies and
the information that a well permit applicant shall include
in the well permit application to address potential im?
pacts. The purpose of these paragraphs is to identify the
public resources that may be impacted by well drilling
and to outline a process to ensure the Department has
suf?cient information to evaluate when determining
whether permit conditions are necessary to prevent a
probable harmful impact to the functions and uses of
those public reSources using the criteria in 
Accordingly, within the context of these provisions, an
impact is a probable harmful effect to the functions and
uses of the public resource.

A more speci?c set of comments recommended adding
schools, hospitals, day care centers, nursing homes and
other similar facilities to the list of public resources.

These facilities have not been added to the list of public
resources included in of this ?nal?form
rulemaking. These types of facilities are not similar in
nature to the other hated public resources (that is, parks,
forests, game lands, wildlife areas, species of special
concern, scenic rivers, natural landmarks, historical or
archeological sites, and public drinking water supplies).

To the extent that commentators were suggesting that
additional protections are needed for these facilities,
Chapter 78a, as well as other regula?ons, permits and
policies implemented by the Department under the Com?
monwealth?s environmental laws establish a comprehen-
sive regulatory scheme for oil and gas well development
activities to ensure protection of public health, safety and
the environment.

A similar set of comments suggested that the Depart-
ment add other waters of the Commonwealth to the list of
public resources. Section 78a.15(f) has not been expanded
in this manner because protection of these waters is
achieved through other provisions in Chapter 78a, as well
as implementation of other water permitting programs
administered by the Department through other environ?
mental laws and regulations. Speci?cally, 78a.15(b.1)
requires additional consideration during the well permit
application review process for any watercourse or any
high quality or exceptional value body of water or any
wetland one acre or greater in size. Importantly, Chapter
T8a contains many provisions, including the requirements
related to erosion and sediment control, surface water
discharges, waste management, onsite processing, protec-
tion of water supplies, water management planning,
secondary containment, well construction and site resto-
ration that ensure protection of waters of the Common?
wealth.

Cover all oil and gas operations

Another group of comments stated that the public
resource impact screening process should apply to all oil
and gas operations, not merely drilling a well. The
Department declined to make this change in this ?nal-
form rulemalring.

Section 7831.15 establishes the well permit application
process and is limited to activities associated with well
construction and development. The requirements of these
sections are designed to address the impacts within the
limit of disturbance of the well site. Other activities

BULLETIN, VOL. 46, N0. 41, OCTOBER 8, 2016

RULES AND REGULATIONS 6463

Department believes that data con?dentiality is already
preserved for an adequate period of time based on the
existing language of 2012 Oil and Gas Act.

All comments received on the proposed rulemaking and
related issues have been addressed in this ?nal-form
rulemaking.

G. Benefits, Costs and Compliance
Bene?ts

The residents of this Commonwealth and the regulated
community will bene?t from this ?nal-form rulemalring.
The process for identifying and considering the impacts to
public resources will ensure that any probable harmful
impacts to public resources will be avoided or mitigated
while providing for the optimal development of natural
gas resources. The regulations that require operators to
conduct an area of review survey and appropriately
monitor wells with the risk of being impacted by hydrau?
lic fracturing activities will minimize potential impacts to
waters of the Commonwealth. The containment systems
and practices requirements for unconventional well sites
will minimize spills and releases of regulated substances
at well sites and ensure that any spills or releases are
properly contained. The amendments to the reporting and
remediation requirements for releases will ensure State-
wide consistency for reporting and remediating spills and
releases.

New planning, noti?cation, construction, operation,
testing and monitoring requirements for pits, tanks,
modular aboveground storage structures, well develop?
ment impoundments and pipelines will help prevent
releases or spills that may otherwise result without these
additional precautions. Additionally, the monitoring and
fencing requirements for pits and impoundments and
unconventional tank valve and access lid requirements
for tanks ensure protection from unauthorized acts of
third parties and damage from wildlife. Further, the
requirements regarding wastewater processing at well
sites will encourage the bene?cial use of wastewater for
drilling and hydraulic fracturing activities.

This ?nal-form rulemalring contains several new noti?-
cation requirements which will enable Department staff
to effectively and ef?ciently coordinate inspections at
critical stages of modular aboveground storage facility
installation, onsite residual waste processing and HDD
activities. Additionally, requiring electronic submission for
well permits, noti?cations and predrill surveys will en-
hance ef?ciency for both the industry and the Depart?
ment. As new areas of this Commonwealth are developed
for natural gas, the regulations will avoid many potential
health, safety and enviroumental issues as well as pro?
vide a consistent and ef?cient approach to natural gas
development in this Commonwealth.

Compliance costs
Unconventional operators? costs
Assumptions

When initially proposing this ?nal-form rulemalung,
the Department estimated based on data available at the
time that there will be approximately 2,600 unconven-
tional wells permitted each year for the next 3 years.

On average, about one of every two permitted uncon?
ventional wells are drilled.

In addition, the Department estimated that there were
an average of three unconventional wells per well site.

Since considerable time has passed since the proposed
rulemaking was published, the Department was able

re-evaluate the rate at which unconventional wells are
permitted and drilled in this Commonwealth and include
data for 2013, 2014 and the ?rst three quarters of 2015.

The Department?s records also show that there are
currently 3,387 unconventional well pads with at least 1
well drilled and a total of 9,486 total unconventional
wells located within this Commonwealth. This equates to
an average of 2.8 wells per pad. In the future, it is
estimated that less well sites will be built as there could
be as many as 22 wells on a pad, based on data ayailable
to the Department.

The cost analysis for this ?nal?form rulemalring must
be factored on a well site basis, not on a per well basis.
Many of the processes proposed for regulation in this
?nal?form rulemaking include activities integral to the
operation of several wells and even several well pads.

Unconventional Wells Unconventional Wells

Y?ar Permitted Drilled
2010 3,364 1,599
2011 3,560 1,960
2012 2,649 1,351
2013 2,965 1,207
2014 3,182 1,327
2015* 1319* 756*

*Data extrapolated from ?rst 3 quarters (1,439 wells
permitted, 567 wells drilled as of September 8, 2015)

Based on the data shown in the previous table which
represents the most recent 5-year period, it is clear that
the Department?s estimate was relatively accurate. The
number of wells permitted exceeded the Department?s
estimate but the percentage of permitted wells that have
been drilled is approximately 46% since 2010 and 41%
since 2013, which is lower than the Department?s original
estimate. The Department does not believe that the new
data supports a change to its original estimate of 2,600
wells permitted per year and 1,300 wells drilled per year
as a reasonable conservative estimate of the potential
unconventional well drilling activity over the next 3
years.

The Department behaves that the number of unconven-
tional wells per well site will rise in time but has
retained the estimate of three wells per well site for the
purposes of this estimate because it is re?ective of
current conditions and what is expected over the next 3
years.

2,600 wells permitted 50% of wells drilled 1,300
wells drilled each year

1,300 wells drilled each year 3 wells per well site 
434 well sites built each year

Cost estimates

The Department reached out to oil and gas operators,
subcontractors and industry groups to derive the cost
estimates of this ?nal-form rulemaking.

Identi?cation of public resources 78a.15)

The requirements in this section ensure that the De-
partment meets its constitutional and statutory obliga?
tions to protect public resources.

The Department received signi?cant public comment on
these provisions from unconventional gas well operators
regarding the cost of implementing the public resource
Screening process requirements in 78a.15(f) and 
Commentators disagreed with the Department?s estimates

BULLETIN, VOL. 46, NO. 41, OCTOBER 8, 2016

6464 RULES AND REGULATIONS

of cost for permit conditions mitigation measure to protect
public resources. Commentators also argued that there
will be considerable expenses related to personnel time,
expert consultants needed for surveys and project delays
in associated with the responses from public resource
agencies. The Department acknowledges that there is
some cost associated with implementing these require-
ments. The total cost of this provision will vary on a
case-by-case basis. This cost is dependent on several
variables including, the number of well sites that are
within the prescribed distances or areas listed, the type
and scope of operations within prescribed distances or
areas, the type of public resource, the functions and uses
of the public resource, speci?c probable harmful impacts
encountered and several other variables and the available
mitigation measure to avoid, mitigate or otherwise mini-
mize impacts. Because so many signi?cant variables
exist, the cost estimate for implementation of the entire
provision will vary. For that reason, the Department
provides the following estimate for speci?c steps which
allow for an estimate to be made.

The ?rst step in the process is identi?cation. The
Department believes this process would be required for
all new Well sites. First an electronic review can be
conducted with the Conservation Explorer?s
online planning tool. This tool will allow operators to
identify the location of the majority of public resources
which require consideration under this ?nal-form rule?
msln'ng. This tool also will allow the operator to identify
potential impacts to threatened and endangered species,
which also must be addressed under Since
the tool may not have data to identify all the public
resources listed in 7 operators will also need
to conduct a ?eld survey of the proposed well site area to
identify public resources. This ?eld survey will likely
include identi?cation of schools and playgrounds 200 feet
from the limit of disturbance of the well site. The
Department estimates the cost of this ?eld survey to be
$2,000 and the cost of the electronic survey to be 
Even though use of the online tool is currently required to
comply with requirements protecting threatened and en-
dangered species, the Department has included the cost
in this estimate nonetheless.

$2,000 434 $868,000
$40 434 $17,360
$868,000 $17,360 $885,360

The second step of the process is consultation with the
public resource agency. This process is only applicable to
well sites which are within the prescribed distances or
areas listed in 78a.15(fl(1l. The Department estimates
that 30% of well sites will fall within these distances or
areas. Operators will be required evaluate the functions
and uses of the public resource, determine any probable
harmful impacts to the public resource and deveIOp any
needed mitigation measures to avoid probable harmful
impact. Operators shall also notify potentially impacted
pubic resource agencies of the impact and provide those
public resource agencies the same information provided to
the Department. Cost of the provision is dependent on the
number of well sites impacted as well as the complexity of
evaluating the functions and uses of the public resource.
The Department estimates the postage will cost $20 per
noin'?cation to public resource agencies.

$20 434 30% $2,604

Due to the complexity of the variables in this process,
the estimate for the cost of evaluating the ?mctions and
uses of the public resource and determining whether

there is a probable harmful impact will vary. In Some
cases, functions and uses of the public resource and any
probable harmful impacts may be immediately obvious
and others may be far more complex and may include
multiple public resources.

The ?nal step in the process is mitigation. The cost
estimate for mitigation will vary. In some circumstances,
an operator may be able to plan the location of the well
site using the planning tool previously discussed to avoid
public resources resulting in zero cost. Any cost associated
with mitigation measures is dependent on many variables
and may be situation speci?c in some cases. While the
Department is unable to provide a Speci?c estimate for
the implementation of this entire provisiom it should be
noted that this cost may be substantial depending on the
location of the well site.

$885,360 $2,604 $887,964

The total cost of this provision is $887,964 (not includ-
ing consultation and mitigation).

Protection of water supplies 783.51)

This section provides the Department?s interpretation of
the water supply restoration and replacement in section
8218(a) of the 2012 Oil and Gas Act. This section seeks
only to provide clarity to existing statutory requirements.
Accordingly, the estimated new cost incurred by uncon-
ventional Operators is 

The total new cost of this provision is 

Area of review and monitoring plans 78a.52o. and
780.73)

$8,720
$8,720 1,300 wells $11,336,000
The total cost of this provision is $11,336,000.

The Department?s 2018 Regulatory Analysis estimated
the compliance cost at $2,000 per new well. That Depart-
ment estimate was made before the introduction of
signi?cant new requirements in 2015, including:

- Researching the depth of identi?ed wells.

0 Development of monitoring methods for identi?ed
wells, including visual monitoring under accompanying
78.73 (relating to general provisions for well construc?
tion and operation).

- Gathering surface evidence concerning the condition
of identi?ed wells.

I Gathering GPS, that is, coordinate data for identi?ed
wells.

- Introduction of a provision of advanced notice to
adjacent operators under accompanying 78.73.

- The assembly of the previously listed data in an area
of review report and monitoring plan and the submission
of the report at least 30 days prior to the start of drilling
the well at well sites where hydraulic fracturing activities
are anticipated.

With the additional items, the cost of compliance is
expected to exceed $2,000 per well.

However, it is important to emphasize that industry
commentators have indicated the majority of the work
required as part of the area of review is already per-
formed by operators in an effort to not only reduce
potential environmental liability, but also to protect the
investment associated with the drilling and stimulation of
a new Well, which represents millions of dollars for a
typical unconventional well.

BULLETIN, VOL. 46, NO. 41, OCTOBER 3, 2016

RULES AND REGULATIONS 6481

Minimum Cemented

Casing Required
Proposed Tbtai Variicai (in feet of
Depth (in feet) casing cemented)
Up to 5,000 400
5,001 to 5,500 500
5,501 to 6,000 600
6,001 to 6,500 700
6,501 to 7,000 800
7,001 to 8,000 1,000
8,001 to 9,000 1,200
9,001 to 10,000 1,400
Deeper than 10,000 1,800

Upon completion of the drilling operations at a well,
the operator shall install and utilize equipment, such as a
shut-off valve of suf?cient rating to contain anticipated
pressure, lubricator or similar device, as may be neces?
sary to enable the well to be effectively shut-in while
logging and servicing the well and after completion of the
Well.

Subchapter E. WELL REPORTING
78.121. Production reporting.

The well operator shall submit an annual produc-
tion and status report for each permitted or registered
well on an individual basis, on or before February 15 of
each year. When the production data is not available to
the operator on a well basis, the operator shall report
production on the most well-speci?c basis available. The
annual production report must include information on the
amount and type of waste produced and the method of
waste disposal or reuse. Waste information submitted to
the Department in accordance with this subsection is
deemed to satisfy the residual waste biennial reporting
requirements of 287.52 (relating to biennial report).

The production report shall be submitted electroni-
cally to the Department through its web site.

CHAPTER 78a. UNCONVENTIONAL WELLS

Subch.

A. GENERAL PROVISIONS

B. PERMITS, TRANSFERS AND OBJECTIONS

0. ENVIRONMENTAL PROTECTION PERFORMANCE
STANDARDS

1) WELL DRILLING, OPERATION AND 

E. WELL REPORTING

BONDING REQUIREMENTS

Subchapter A. GENERAL PROVISIONS

Sec.
783.. 1. De?nitions.
7821.2. Applicability.

783.1. De?nitions.

The following words and terms, when used in this
chapter, have the following meanings, unless the context
clearly indicates otherwise, or as otherwise provided in
this chapter:

ABACT#Mtidegrwaiion best available combination of
technologies?The term as de?ned in 102.1 (relating to
de?nitions).

Abandoned water well?

A water well that is no longer equipped in such a
manner as to be able to draw groundwater.

(ii) The term includes a water well where the pump,
piping or electrical components have been disconnected or
removed or when its use on a regular or prescribed basis
has been discontinued.

The term does not include a water well that is not
currently used, but is equipped or otherwise properly
maintained in such a manner as to be able to draw
groundwater as an alternative, backup or supplemental
water supply.

Accredited laboratory?A laboratory accredited by the
Department under Chapter 252 (relating to environmen?
tal laboratory accreditation).

Act?58 3201?3274 (relating to develop?
ment).

Act 2?The Land Recycling and Environmental
Remediation Standards Act (35 RS. 6026.101?
6026.908).

Anti~icing?Brine applied directly to a paved road prior
to a precipitation event.

Approximate original conditions?Reclamation of the
land affected to preconstruction contours so that it closely
resembles the general surface con?guration of the land
prior to construction activities and blends into and
complements the drainage pattern of the surrounding
terrain, and can support the land uses that existed prior
to the applicable oil and gas operations to the extent
practicable.

Attainabie bottom?The depth, approved by the Depart-
ment, which can be achieved after a reasonable effort is
expended to clean out to the total depth.

Barrel?A unit of volume equal to 42 US liquid gallons.

Body of water?The term as de?ned in 105.1 (relating
to de?nitions).

Borrow pit?An area of earth disturbance activity
where rock, stone, gravel, sand, soil or similar material is
excavated for construction of well sites, access roads or
facilities that are related to oil and gas development.

Building?An occupied structure with walls and roof
Within which persons live or customarily work.

Casing seat?The depth to which casing is set.

Cement?A mixture of materials for bonding or sealing
that attains a 7-day maximum permeability of 0.01
millidarcies and a 24-hour compressive strength of at
least 500 psi in accordance with applicable standards and
speci?cations.

Cement job log?A written record that documents the
actual procedures and speci?cations of the cementing
operation.

Centralized impoundment?A facility authorized by a
Permit for a Centralized Impoundment Dam for Oil and
Gas Operations (DEP 8000-PM-OOGM0084).

Certi?ed mad?Any veri?able means of paper docu?
ment delivery that con?rms the receipt of the document
by the intended recipient or the attempt to deliver the
document to the proper address for the intended recipi?
ent.

Coal area?An area that is underlain by a workable
coal seam.

Coal protective casing?A string of pipe which is in?
stalled in the well for the purpose of coal segregation and
protection. In some instances the coal protective casing
and the surface casing may be the same.

BULLETIN, VOL. 46, N0. 41, OCTOBER 3, 2016

6482 RULES AND REGULATIONS

Common. areas of a school?s property?An area on a
school?s property accessible to the general public for
recreational purposes. For the purposes of this de?nition,
a school is a facility providing elementary, secondary or
postsecondary educational services.

Condensate?A low-density, high? API gravity liquid hy~
drocarbon phase that generally occurs in association with
natural gas. For the purposes of this de?nition, high?API
gravity is a speci?c gravity scale developed by the
American Petroleum Institute for measuring the relative
density of various petroleum liquids, expressed in de-
grees.

Conductor pipe?A short string of large-diameter casing
used to stabilize the top of the wellbore in shallow
unconsolidated formations.

Deepest fresh groundwater?The deepest fresh ground-
water bearing formation penetrated by the wellbore as
determined from drillers logs from the well or from other
wells in the area surrounding the well or from historical
records of the normal surface casing seat depths in the
area surrounding the well, whichever is deeper.

De-icing?Brine applied to a paved road after a precipi-
tation event.

Drill cuttings?Rock cuttings and related mineral resi?
dues generated during the drilling of an oil or gas well.

Floodplain?The area inundated by the IOU-year ?ood
as identi?ed on maps and flood insurance studies pro-
vided by the Federal Emergency Management Agency, or
in the absence of these maps or studies or any evidence to
the contrary, the area within 100 feet measured horizon~
tally from the top of the bank of a perennial stream or 50
feet from the top of the bank of an intermittent stream.

Freeboard?The Vertical distance between the surface of
an impounded or contained ?uid and the lowest point or
opening on a lined pit edge or open top storage structure.

Fresh groundwater?Water in that portion of the gener?
ally recognized hydrologic cycle which occupies the pore
spaces and fractures of saturated subsurface materials.

Gas storage ?eld?A gas storage reservoir and all of the
gas storage wells connected to the gas storage reservoir.

Gas storage reservoir?The portion of a subsurface
geologic formation or rock strata used for or being tested
for storage of natural gas that:

Has suf?cient porosity and permeability to allow gas,
to be injected or withdrawn, or both.

(ii) Is bounded by strata of insuf?cient porosity or
permeability, or both, to allow gas movement out of the
reservoir.

Contains or will contain injected gas geologically or
by pressure control.

Gas storage well?A well located and used in a gas
storage reservoir for injection or withdrawal purposes, or
an observation Well.

Gathering pipeline?A pipeline that transports oil, liq-
uid hydrocarbons or natural gas from individual wells to
an intrastate transmission pipeline regulated by the
Public Utility Commission or interstate
tranSmission pipeline regulated by the Federal Energy
Regulatory Commission.

Gel?A slurry of clay or other equivalent material and
water at a ratio of not more than seven barrels of water
to each 100 pounds of clay or other equivalent matter.

Inactive well?A well granted inactive status by the
Department under section 3214 of the act (relating to
inactive status) and 78a.101 (relating to general provi-
Sions).

Intermediate casing?A string of casing set after the
surface casing and before production casing, not to in?
clude coal protection casing, that is used in the wellbore
to isolate, stabilize or provide well control.

L.E.L.~Lower explosive limit.

Limit of disturbance??The boundary Within which it is
anticipated that earth disturbance activities (including
installation of best management practices) will take place.

Mine in?uenced water?Any of the following:
Water in a mine pool.
(ii) Surface discharge of water caused by mining activi-

ties that pollutes or may create a threat of pollution to
waters of the Commonwealth.

A surface water polluted by mine pool water.
(iv) A surface discharge caused by mining activities.

Modular aboveground storage structure?An
aboveground structure used to store wastewater that
requires ?nal assembly at a well site to function and.
which can be disassembled and moved to another well
site after use.

Noncementing material?A mixture of very ?ne to
coarse grained nonbonding materials, including unwashed
crushed rock, drill cuttings, earthen mud or other equiva-
lent material approved by the Department.

Noncoal area?An area that is not underlain by a
workable coal seam.

Nonporous material?Nontoxic earthen mud, drill cut?
tings, ?re clay, gel, cement or equivalent materials ap~
proved by the Department that will equally retard the
movement of ?uids.

Nonvertical unconventional well?

An unconventional well drilled intentionally to devi?
ate from a vertical axis

(ii) The term includes wells drilled diagonally and
wells that have horizontal bore holes

Observation well~A well used to monitor the opera?
tional integrity and conditions in a gas storage reservoir,
the reservoir protective area, or strata above or below the
gas storage horizon.

Oil and gas operations?The term includes the follow~
ing:

Well site preparation, construction, drilling, hydrau?
lic fracturing, completion, production, operation, altera-
tion, plugging and site restoration associated with an oil
or gas well.

(ii) Water withdrawals, residual waste processing, wa-
ter and other fluid management and storage used exclu?
sively for the development of o? and gas wells.

Construction, installation, use, maintenance and
repair of:

(A) Oil and gas well development, gathering and trans?
mission pipelines.

(B) Natural gas compressor stations.

(C) Natural gas processing plants or facilities perform-
ing equivalent functions.

BULLETIN, VOL. 46, N0. 41, OCTOBER 8, 201B

RULES AND REGULATIONS 5483

(iv) Construction, installation, use, maintenance and
repair of all equipment directly associated with activities
in subparagraphs to the extent that the equip?
ment is necessarily located at or immediately adjacent to
a well site, impoundment area, oil and gas pipeline,
natural gas compressor station or natural gas processing
plant.

Earth disturbance associated with oil and gas explo?
ration, production, processing, or treatment operations or
transmission facilities.

Other critical communities?

Species of special concern identi?ed on a PNDI
receipt, including plant or animal species:

(A) In a proposed status categorized as proposed an-
dangered, proposed threatened, proposed rare or candi?
date.

(B) That are classi?ed as rare or tentatively undeter?
mined.

(ii) The term does not include threatened and endan?
gered species.

Owner_

A person who owns, manages, leases, controls or
possesses a well or coal property.

(ii) The term does not apply to orphan wells, except
when the Department determines a prior owner or opera-
tor bene?ted from the well as provided in section 3220(a)
of the act (relating to plugging requirements).

PCSM?Post-construction stormwater management?
The term as de?ned in 102.1.

PCSM plan?The term as de?ned in 102.1.

Natural Diversity Inventory?The
Natural Heritage Program?s database con~
teining data identifying and describing this Common-
wealth?s ecological information, including plant and ani-
mal species classi?ed as threatened and endangered as
well as other critical communities provided by the De-
partment of Conservation and Natural Resources, the
Fish and Boat Commission, the Game Commission and
the United States Fish and Wildlife Service. The database
informs the online environmental review tool. The data-
base contains only thosa known occurrences of threatened
and endangered species and other critical communities,
and is a component of the Conservation
Explorer.

PNDI receipt?The results generated by the 
nia Natural Diversity Inventory Environmental Review
Tool containing information regarding threatened and
endangered species and other critical communities.

PPC plan?Preparedness, Prevention and Contingency
plan?A written preparedness, prevention and contin-
gency plan.

Perimeter area?An area that begins at the outside coal
boundaries of an operating coal mine and extends within
1,000 feet beyond these boundaries or an area within
1,000 feet beyond the mine permit boundaries of a coal
mine already projected and permitted but not yet being
operated.

Permanently cemented?Surface casing or coal protec-
tive casing that is cemented until cement is circulated to
the surface or is cemented with a calculated volume of
cement necessary to ?ll the theoretical annular space
plus 20% excess.

Pit?A natural topographic depression, manmade exca-
vation or diked area formed primarily of earthen materi-
als designed to hold ?uids, semi?uids or solids.

Playgro and??

An outdoor area provided to the general public for
recreational purposes.

(ii) The term includes community-operated recreational
facilities.

Pre-wetting?Miidng brine with antist material prior
to roadway application.

Primary containment?A pit, tank, vessel, modular
aboveground storage structure, temporary storage facility
or other equipment designed to hold regulated substances
including all piping and other appurtenant facilities
located on the well site.

Private water supply?A water supply that is not a
public water supply.

Process or processing?The term has the same meaning
as ?processing? as de?ned in section 103 of the Solid
Waste Management Act (35 PS. 6018.103).

Production casing?A string of pipe other than surface
casing and coal protective casing which is run for the
purpose of con?ning or conducting hydrocarbons and
associated ?uids from one or more producing horizons to
the surface.

Public resource agency?An entity responsible for man-
aging a public resource identi?ed in 78a.15(d) or 
(relating to application requirements) including the De-
partment of Conservation and Natural Resources, the
Fish and Boat Commission, the Game Commission, the
United States Fish and Wildlife Service, the United
States National Park Service, the United States Army
Corps of Engineers, the United States Forest Service,
counties, municipalities and playground owners.

Public water supply?A source of water used by a water
purveyor.

Regional groundwater table~

The ?uctuating upper water level surface of an
uncon?ned or con?ned aquifer where the hydrostatic
pressure is equal to the ambient atmospheric pressure.

(ii) The term does not include the perched water table
or the seasonal high groundwater table.

Regulated substance?The term as de?ned in section
103 of Act 2 (35 RS. 6026.103).

Residual waste?The term as de?ned in 287.1 (relat-
ing to de?nitions).

Retrievable?When used in conjunction with surface
casing, coal protective casing or production casing, the
casing that can be removed after exerting a prudent effort
to pull the casing while applying a pulling force at least
equal to the casing weight plus 5,000 pounds or 120% of
the casing weight, whichever is greater.

Seasonal high groundwater table?The saturated condi-
tion in the soil pro?le during certain periods of the year.
The condition can be caused by a slowly permeable layer
within the soil pro?le and is commonly indicated by the
presence of soil mottling.

Secondary containment?A physical barrier speci?cally
designed to minimize releases into the environment of
regulated Substances from primary containment or well
development pipelines, to prevent comingling of incompat-

BULLETIN, VOL. 46, NO. 41, OCTOBER 8, 2016

RULES AND REGULATIONS 6435

7851.2. Applicability.

This chapter applies to unconventional wells and super-
sedes any regulations in Chapter 78 (relating to oil and
gas wells) applicable to unconventional wells.

Suhchapter B. PERMITS, TRANSFERS AND
OBJECTIDNS

PERMITS AND TRANSFERS

See.

78a.11. Permit requirements.

78a.12. Compliance with permit.

78a.13. Permit transfers.

78:31.14. Transfer of well ownership or change of address.
lMale. Application requirements.

7851.16. Accelerated permit review.

78a.17. Permit expiration and renewal.

78a.18. Disposal and enhanced recovery well permits.
78a.19. Permit application fee schedule.

OBJECTIONS

78a.21. Opportunity for objections and conferences; surface landowners.

7821.22. Objections by owner or operator of coal mine.

78a.23. Time for ?ling objections by owner or operator of coal mine.

78a.24. Information to be provided with objections by owner or operator
of coal mine.

78a.25. Conferences?general.

78a.26. Agreement at conference.

78a.27. Continuation of conference.

78a.28. Final action if objections do not proceed to panel.

7851.29. Composition of panel.

7811.80. Jurisdiction of panel.

78a.31. Scheduling of meeting by the panel.

7851.32. Recommendation by the panel.

7851.33. Effect of panel on time for permit issuance.

PERMITS AND TRANSFERS
7821.11. Permit requirements.

No person may drill or alter a well unless that
person has ?rst obtained a permit from the Department.

(In) No person may operate a well unless one of the
following conditions has been met:

(1) The person has obtained a permit under the act.
(2) The person has registered the well under the act.

(3) The well was in operation on April 18, 1985, under
a permit that was obtained under the Gas Operations
Well?Drilling Petroleum and Coal Mining Act (52 RS.
2104, 2208, 2601 and 2602) (Repealed).

78a.12. Compliance with permit.

A person may not drill, alter or operate a well except in
accordance with a permit or registration issued under the
act and in compliance with the terms and conditions of
the permit, this chapter and the statutes under which it
was promulgated. A copy of the permit shall be kept at
the well site during drilling or alteration of a well.

783.13. Permit transfers.

No transfer, assignment or sale of rights granted
under a permit or registration may be made without prior
written approval of the Department. Permit transfers
may be denied for the reasons set forth in section
and (5) of the act (relating to well permits).

The Department may require the transferee to
ful?ll the drilling, plugging, well site restoration, water
supply replacement and other requirements of the act,
regardless of whether the transferor started the activity
and regardless of whether the transferor failed to prop-
erly perform the transferor?s obligations under the act.

BULLETIN, VOL

78a.14. Transfer of well ownership or change of
address.

Within 30 days after the sale, assignment, transfer,
conveyance or exchange of a well, the new owner or
operator shall notify the Department, in writing, of the
transfer of ownership.

The notice must include the following information:

(1) The names, addresses and telephone numbers of
the former and new owner, and the agent if applicable.

(2) The well permit or registration number.
(3) The effective date of the transfer of ownership.

(4) An application for a well permit transfer if there is
a change in the well operator.

The permittee shall notify the Department of a
change in address or name within 30 days of the change.

783.15. Application requirements.

An application for a well permit shall be submitted
electronically to the Department on forms provided
through its web site and contain the information required
by the Department to evaluate the application.

The permit application will not be considered com-
plete until the applicant submits a complete and accurate
plat, an approvable bond or other means of complying
with Subchapter (relating to bonding requirements)
and section 3225 of the act (relating to bonding), the fee
in compliance with 78a.19 (relating to permit applica-
tion fee schedule), proof of the noti?cations required
under section 3211(b.1) of the act (relating to well
permits), necessary requests for variance or waivers or
other documents required to be furnished by law or the
Department and the information in subsections (13.1),
and The person named in the permit
shall be the same person named in the bond or other
security.

If the proposed limit of disturbance of the well
site is within 100 feet measured horizontally from any
watercourse or any high quality or exceptional value body
of water or any wetland 1 acre or greater in size, the
applicant shall demonstrate that the well site location
will protect those watercourses or bodies of water. The
applicant may rely upon other plans developed under this
chapter or approved by the Department to make this
demonstration, including:

(1) An erosion and sediment control plan or permit
consistent with Chapter 102 (relating to erosion and
sediment control).

(2) A water obstruction and encroachment permit is?
sued under Chapter 105 (relating to dam safety and
waterway management).

(3) Applicable portions of the PPC plan prepared in
accordance with 78a.55(a) and (relah'ng to control
and diaposal planning; emergency response for unconven?
tional wells).

(4) Applicable portions of the emergency respouse plan
prepared in accordance with 

(5) Applicable portions of the site containment plan
prepared in accordance with section 3218.2 of the act
(relating to containment for unconventional wells).

For purposes of compliance with section 3215(a) of
the act (relating to well location restrictions), an aban-
doned water well does not constitute a water well.

. 46, N0. 41, OCTOBER 8, 2015

6486 RULES AND REGULATIONS

The applicant shall submit information identifying
parent and subsidiary business corporations operating in
this Commonwealth with the ?rst application submitted
after October 8, 2016, and provide any changes to this
information with each subsequent application.

The well permit application must include a detailed
analysis of the impact of the well, well site and access
road on threatened and endangered species. This analysis
must include:

(1) A PNDI receipt.

(2) If any potential impact is identi?ed in the PNDI
receipt to threatened or endangered species, demonstra-
tion of how the impact will be avoided or minimized and
mitigated in accordance with State and Federal laws
pertaining to the protection of threatened or endangered
species and critical habitat. The applicant shall provide
written documentation to the Department supporting this
demonstration, including any avoidance/mitigation plan,
clearance letter, determination or other correspondence
resolving the potential species impact with the applicable
public resource agency.

(8) If an applicant seeks to locate a well on an existing
well site where the applicant has obtained a permit under
102.5 (relating to permit requirements) and complied
with (relating to permit applications and
fees), the applicant may comply with subsections 
and if the permit was obtained within 2 years from
the receipt of the application submitted under this sec-
tion. .

An applicant proposing to drill a. well at a location
that may impact a public resource as provided in para-
graph (1) shall notify the applicable public resource
agency, if any, in accordance with paragraph (2). The
applicant shall also provide the information in paragraph
(3) to the Department in the well permit application.

(1) This subsection applies if the proposed limit of
disturbance of the well site is located:

In or within 200 feet of a publicly owned park,
forest, game land or wildlife area.

(ii) In or within the corridor of a State or National
scenic river.

Within 200 feet of a National natural landmark.

(iv) In a location that will impact other critical commu?
nities.

Within 200 feet of a historical or archeological site
listed on the Federal or State list of historic places.

(vi) Within 200 feet of common areas on a school?s
property or a playground.

(vii) Within zones 1 or 2 of a wellhead protection area
as part of a wellhead protection program approved under
109.713 (relating to wellhead protection program).

Within 1,000 feet of a water well, surface water
intake, reservoir or other water supply extraction point
used by a water purveyor.

(2) The applicant shall notify the public resource
agency responsible for managing the public resource
identi?ed in paragraph (1), if any. The applicant shall
forward by certi?ed mail a copy of the plat identifying the
proposed limit of disturbance of the well site and informa-
tion in paragraph (3) to the public resource agency at
least 30 days prior to submitting its well permit applica?
tion to the Department. The applicant shall submit proof
of notification with the well permit application. From the
date of noti?cation, the public resource agency has 30

days to provide written comments to the Department and
the applicant on the functions and uses of the public
resource and the measures, if any, that the public re?
source agency recommends the Department consider to
avoid, minimize or otherwise mitigate probable harmful
impacts to the public resource where the well, well site
and access road is located. The applicant may provide a
response to the Department to the comments.

(3) The applicant shall include the following informa?
tion in the well permit application on forms provided by
the Department:

An identi?cation of the public resource.

(ii) A description of the functions and uses of the public
resource.

A description of the measures proposed to be taken
to avoid, minimize or otherwise mitigate impacts, if any.

(4) The informai?on required under paragraph (3) shall
be limited to the discrete area of the public resource that
may be affected by the well, well site and access road.

The Department will consider the following prior to
conditioning a well permit based on impacts to public
resources:

(1) Compliance with all applicable statutes and regula?
tions.

(2) The proposed measures to avoid, minimize or other?
wise mitigate the impacts to public resources.

(3) Other measures necessary to protect against a
probable harmful impact to the functions and uses of the
public resource.

The comments and recommendations submitted by
public resource agencies, if any, and the applicant?s
reapcnse, if any.

(5) The optimal development of the gas resources and
the property rights of gas owners.

An applicant proposing to drill a well that involves
1 acre to less than 5 acres of earth disturbance over the
life of the project and is located in a watershed that has a
designated or existing use of high quality or exceptional
value under Chapter 93 (relating to water quality stan?
dards) shall submit an erosion and sediment control plan
consistent with Chapter 102 with the well permit applica-
tion for review and approval and shall conduct the earth
disturbance in accordance with the approved erosion and
sediment control plan.

78a.16. Accelerated permit review.

In cases of hardship, an operator may request an
accelerated review of a well permit application. For the
purposes of this section, hardship includes cases where
immediate action is necessary to protect public health or
safety, to control pollution or to effect other environmen-
tal or safety measures, and extraordinary circumstances
beyond the control of the operator. Permits issued shall be
consistent with the requirements of the act.

783.17. Permit expiration and renewal.

A well permit expires 1 year after issuance if
drilling has not started. If drilling is started within 1
year after issuance, the well permit expires unless drill?
ing is pursued with due diligence. Due diligence for the
purposes of this subsection means completion of drilling
the well to total depth within 16 months of issuance. A
permittee may request an extension of the 16?month

BULLETIN, VOL. 46, N0. 41, OCTOBER 8, 2016

6490 RULES AND REGULATIONS

partment?s satisfaction that the restored or replaced
water supply is adequate for the purposes served by the
supply.

Tank trucks or bottled water are acceptable only as
temporary water replacement for a period approved by
the Department and do not relieve the operator of the
obligation to provide a restored or replaced water supply.

If the well operator and the water user are unable
to reach agreement on the means for restoring or replac-
ing the water supply, the Department or either party may
request a conference under section 3251 of the act
(relating to conferences).

A well operator who receives notice from a land?
owner, water purveyor or affected person that a water
supply has been affected by pollution or diminution shall
report receipt of notice from an affected person to the
Department within 24 hours of receiving the notice.
Notice shall be provided electronically to the Department
through its web site.

7321.52. Predrilling or prealteration survey.

A well operator who wishes to preserve its defense
under section 3218(d)(2)(i) of the act (relating to protec?
tion of water supplies) that the pollution of a water
supply existed prior to the drilling or alteration of the
well shall conduct a predrilling or prealteration survey in
accordance with this section. For the purposes of this
section, ?survey? means all of the predrilling or prealtera~
tion water supply samples associated with a single well.

A person who wishes to document the quality of a
water supply to support a future claim that the drilling or
alteration of the well affected the water supply by
pollution may conduct a predrilling or prealteration sur-
vey in accordance with this section.

The survey shall be conducted by an independent
laboratory. A person independent
of the well owner or well operator, other than an em?
ployee of the accredited laboratory, may collect the sample
and document the condition of the water supply, if the
accredited laboratory af?rms that the sampling and docu-
mentation is performed in accordance with the laborato-
ry?s approved sample collection, preservation and han-
dling procedure and chain of custody.

An operator electing to preserve its defenses under
section 3218(d)(2)(i) of the act shall provide a report
containing a copy of all the sample results taken as part
of the survey electronically to the Department on forms
provided through its web site 10 business days prior to
the start of drilling of the well that is the subject of the
survey. The operator shall provide a copy of any sample
results to the landowner or water purveyor within 10
business days of receipt of the sample results. Survey
results not received by the Department within 10 busi?
ness days may not be used to preserve the operator?s
defenses under section 3218(d)(2)(i) of the act.

The report describing the results of the survey must
contain the following information:

(1) The location of the water supply and the name of
the surface landowner or water purveyor.

(2) The date of the survey, and the name of the
independent laboratory and the
person who conducted the survey.

(8) A description of where and how the samples were
collected.

(4) A description of the type and age, if known, of the
water supply, and treatment, if any.

(5) The name of the well operator, name and number of
well to be drilled and permit number if known.

(6) The results of the laboratory analysis.

A well operator who wishes to preserve the defense
under section 3218(d)(2)(ii) of the act that the landowner
or water purveyor refused the operator access to conduct
a survey shall con?rm the desire to conduct this survey
and that access was refused by issuing notice to the
person by certi?ed mail, or otherwise document that
access was refused. The notice must include the following:

(1) The operator?s intention to drill or alter a well.

(2) The desire to conduct a predrilling or prealteration
survey.

(3) The name of the person who requested and was
refused access to conduct the survey and the date of the
request and refusal.

(4) The name and address of the well operator and the
address of the Department, to which the water purveyor
or landowner may respond.

The operator of an unconventional well shall pro-
vide written notice to the landowner or water purveyor
indicating that the presumption established under section
3218(c) of the act may be void if the landowner or water
purveyor refused to allow the operator access to conduct a
predrilling or prealteration survey. Proof of written notice
to the landowner or water purveyor shall he provided to
the Department for the operator to retain the protections
under section 3218(d)(2)(ii) of the act. Proof of written
notice will be presumed if provided in accordance with
section 3212(a) of the act (relating to permit objections).

783.5211. Area of review.

The operator shall identify the surface and bottom
hole locations of any of the following having well bore
paths within 1,000 feet measured horizoutally from the
vertical well bore and 1,000 feet measured ?'om the
surface above the entire length of a horizontal well bore:

(1) Active wells.

(2) Inactive wells.

(3) Orphan wells.

(4) Abandoned wells.

(5) Plugged and abandoned wells.

Identi?cation of wells listed in subsection must
be accomplished by the following:

(1) Conducting a review of the Department?s well data?
bases and other available well databases.

(2) Conducting a review of historical sources of infor-
mation, such as applicable farm line maps, where acces?
sible.

(3) Submitting a questionnaire by certi?ed mail on
forms provided by the Department to landowners whose
property is within the area identi?ed in subsection 
regarding the precise location of wells on their property.

The operator shall submit a report summarizing the
review, including:

(1) A plat showing the location and GPS codrdinates of
all wells identi?ed under subsection 

(2) Proof that the operator submitted questionnaires
under subsection 

(3) A monitoring plan for wells required to be moni-
tored under 78a.73(c) (relating to general provision for

BULLETIN, VOL. 46, NO. 41, OCTOBER 3, 2016

RULES AND REGULATIONS 6491

well construction and operation), including the methods
the operator will employ to monitor these wells.

(4) To the extent that information is available, the true
vertical depth of identi?ed wells.

(5) The sources of the information provided for identi?
?ed wells.

(6) To the extent that information is available, surface
evidence of failed well integrity for any identi?ed well.

The operator shall submit the report required under
subsection to the Department at least 30 days prior to
the start of drilling the well or at the time the permit
application is submitted if the operator plans to start
drilling the well less than 30 days ?'om the date of permit
issuance. The report shall be provided to the Department
electronically through the Department?s web site.

The Department may require other information
necessary to review the report submitted under subsec?
tion The Department may make a determination that
additional measures are needed, on a case?by?case basis,
to ensure protection of waters of the Commonwealth.

?78a.53. Erosion and sediment control and
stormwater management.

Any person proposing or conducting earth disturbance
activities associated with oil and gas operations shall
comply with Chapter 102 (relating to erosion and sediw
ment control). Best management practices for erdsion and
sediment control and stormwater management for oil and
gas operations are listed in the Erosion and Sediment
Pollution Control Program Manual, Commonwealth of
Department of Environmmtal Protection,
No. 363?2134?008, as amended and updated, the 
vania Stormwater Best Management Practices Manual,
Commonwealth of Department of Environ?
mental Protection, No. 3638-0300-0032, as amended and
updated, the Oil and Gas Operators Manual, Common?
wealth of Department of Environmental
Protection, No. 550?0300?001, as amended and updated,
and Riparian Forest Ba?er Guidance, Commonwealth of
Department of Environmental Protection,
No. 895?5600?001, as amended and updated.

7821.54. General requirements.

The well operator shall control and dispose of ?uids,
residual waste and drill cuttings, including tophole water,
brines, drilling ?uids, drilling muds, stimulation ?uids,
well servicing ?uids, oil, production ?uids and drill
cuttings, in a manner that prevents pollution of the
waters of the Commonwealth and in accordance with
and and with the stat-
utes under which this chapter is promulgated.

7821.55. Control and disposal planning; emergency
response for unconventional wells.

Preparation and implementation of plan for oil and
gas operations. Persons conducting oil and gas operations
shall prepare and implement site~speci?c PPC plans
according to 91.34 and 102.5(1) (relating to activities
utilizing pollutants; and permit requirements).

(13) Preparation and implementation of plan for well
sites. In addition to the requirements in subsection 
the well operator shall prepare and develop a site-speci?c
PPC plan prior to storing, using, or generating regulated
substances on a well site from the drilling, alteration,
production, plugging or other activity associated with a
gas well or transporting those regulated substances to, on
or from a well site.

Containment practices. The well operator?s PPC
plan must describe the containment practices to be

utilized and the area of the well site where primary and
secondary containment will be employed as required
under 78a.64a (relating to secondary containment). The
PPC plan must include a description of the equipment to
be kept onsite during drilling and hydraulic fracturing
operations that can be utilized to prevent a spill from
leaving the well site.

Requirements. The well operator?s PPC plan must
also identify the control and disposal methods and prac?
tices utilized by the well operator and be consistent with
the act, The Clean Streams Law (35 RS. 691.1w-
691.1001), the Solid Waste Management Act (35 RS.
6018.101?6018.1003) and 78a.54, 78a.56~e78a.58
and 78a.60?78a.61. The PPC plan must also include a
pressure barrier policy developed by the operator that
identi?es barriers to be used during identi?ed operations.

Revisions. The well operator shall revise the PPC
plan prior to implementing a change to the practices
identi?ed in the PFC plan.

Copies. A copy of the well operator?s PPC plan shall
be provided to the Department, the Fish and Boat
Commission or the landowner upon request and shall be
available at the site during drilling and completion
activities for review.

Guidelines. With the exception of the pressure
barrier policy required under subsection a PPC plan
developed in conformance with the Guidelines for the
Development and Implementation of Environmental Emer-
gency Response Plans, Commonwealth of 
Department of Environmental Protection, No. 400-2200-
001, as amended and updated, will be deemed to meet the
requirements of this section.

Emergency contacts. A list of emergency contact
phone numbers for the area in which the well site is
located must be included in the PPC plan and be
prominently displayed at the well site during drilling,
completion or alteration activities.

Emergency response for unconventional well sites.

(1) Applicability. This subsection applies to unconven-
tional wells.

(2) De?nitions. For the purposes of this subsection, the
following de?nitions apply:

Access road~A road connecting a well site to the
nearest public road, private named road, administrative
road with a name and address range, or private unnamed
road with an address range.

Address?A location, by reference to a road or a land?
mark, made by a county or municipality responsible for
assigning addresses within its jurisdiction.

Administrative road?A road owned and maintained by
the Commonwealth open to the public at the discretion of
the Commonwealth that may or may not have a name
and address range.

Emergency responder?"Police, ?re?ghters, emergency
medical technicians, paramedics, emergency management
personnel, public health personnel, State certi?ed hazard~
ous materials response teams, Department emergency
personnel and other personnel authorized in the course of
their occupations or duties, or as an authorized volunteer,
to respond to an emergency.

EntrancemThe point where the access road to a well
site connects to the nearest public road, private named
road, administrative road with a name and address
range, or a private unnamed road with an address range.

GPS coordinates?The coordinates in latitude and lon-
gitude as expressed in degrees decimal to at least six

BULLETIN, VOL. 46, NO. 41, OCTOBER 8, 2015

 

RULES AND REGULATIONS 6495

tank prior to installation. Registration shall utilize forms
provided by the Department and be submitted electroni-
cally to the Department through its web site.

All new, refurbished or replaced aboveground stor?
age tanks that store brine or other ?uid produced during
operation of the well must comply with the corrosion
control requirements in 245.531?245.534 (relating to
corrosion and deterioration prevention), with the excep-
tion of use of Department?certi?ed inspectors to inspect
interior linings or coatings.

All new, refurbished or replaced underground stor-
age tanks that store brine or other ?uid produced during
operation of the well must comply with the corrosion
control requirements in 245.432 (relating to operation
and maintenance including corrosion protection) with the
exception of use of Departmentcerti?ed inspectors to
inspect interior linings.

All new, refurbished or replaced tanks storing brine
or other ?uids produced during operation of the well must
be reasonably protected from unauthorized acts of third
parties. the tank is surrounded by a fence, tank
valves and access lids must utilize locks, open end plugs
or removable handles and ladders on tanks must be
retractable or other measures that prevent access by
third parties.

Tanks storing brine or other ?uids produced during
operation of the Well shall be inspected by the operator at
least once per calendar month and documented. De?cien?
cies noted during the inspection shall be addressed and
remedied. When substantial modi?cations are necessary
to correct de?ciencies, they shall be made in accordance
with manufacturer?s speci?cations and applicable engi-
neering design criteria. Any de?ciencies identi?ed during
the inspection shall be reported to the Department elecw
tronically through its web site within 8 days of the
inspection and remedied prior to continued use of the
tank. Inspection records shall be maintained for 1 year
and made available to the Department upon request.

7821.58. Onsite processing.

The operator may request approval by the Depart?
ment to process ?uids generated by the development,
drilling, stimulation, alteration, operation or plugging of
oil or gas wells or mine in?uenced water at the well site
where the ?uids were generated or at the well site where
all of the ?uid is intended to be bene?cially used to
develop, drill or stimulate a well. The request shall be
submitted on forms provided by the Department and
demonstrate that the processing operation will not result
in pollution of land or waters of the Commonwealth.

Approval from the Department is not required for
the following activities conducted at a well site:

(1) Mining ?uids with freshwater.
(2) Aerating ?uids.
(3) Filtering solids from ?uids.

Activities described in subsection shall be con~
ducted within secondary containment.

An operator processing ?uids or drill cuttings gen?
erated by the development, drilling, stimulation, altera?

tion, operation or plugging of oil or gas wells shall?

develop an action plan specifying procedures for monitor?
ing for and responding to radioactive material produced
by the treatment processes, as well as related procedures
for training, noti?cation, recordkeeping and reporting.
The action plan shall be prepared in accordance with the
Department?s Guidance Document on Radioactivity Moni-

toring at Solid Waste Processing and Disposal Facilities,
Commonwealth of Department of Environ?
mental Protection, No. 250-3100~001, as amended and
updated, or in a manner at least as protective of the
environment, facility staff and public health and safety
and which meets all statutory and regulatory require-
ments. -

The operator may request to process drill cuttings
only at the well site where those drill cuttings were
generated by submitting a request to the Department for
approval. The request shall be submitted on forms pro-
vided by the Department and demonstrate that the
processing operation will not result in pollution of land or
waters of the Commonwealth.

Processing residual waste generated by the develop-
ment, drilling, stimulation, alteration, operation or plug-
ging of oil or gas wells other than as provided for in
subsections and shall comply with the Solid Waste
Management Act (35 PS. 

Processing of ?uids in a manner approved under
subsection will be deemed to be approved at subse?
quent well sites provided the operator noti?es the Depart-
ment of location of the well site where the processing will
occur at least 3 business days prior to the beginning of
processing operations. The notice shall be submitted
electronically to the Department through its web site and
include the date activities will begin.

Sludges, ?lter cake or other solid waste remaining
after the processing or handling of ?uids under subsec-
tion or including solid waste mixed with drill
cuttings, shall be characterized under 287.54 (relating
to chemical analysis of waste) before the solid waste
leaVes the well site.

78a.59a. Impoundment embankments.

Embankments constructed for well development im-
poundments for oil and gas operations must meet the
following requirements:

(1) The foundation for each embankment shall be
stripped and grubbed to a minimum depth of 2 feet below
existing contour prior to any placement and compaction of
?ll.

(2) Any springs encountered in the embankment foun?
dation area shall be drained to the toe of the
embankment with a drain section 2 feet by 2 feet in
dimension consisting of Type A sand, com-
pacted by hand tamper. Geotextiles may not be used
around sand. The last 3 feet of this drain at the
slope must be constructed of AASHTO 8
material.

(3) The minimum top width of the embankment must
be 12 feet.

(4) The inside and outside slope must have a slope no
steeper than 3 horizontal to 1 vertical.

(5) Soils to be used for embankment construction must
be classi?ed in accordance with ASTM 13?2487 (Uni?ed
Soils Classi?cation). Soil samples must be classi?ed at a
minimum rate of one sample per 10,000 cubic yards of
placed ?ll with at least one test per source with an
additional test conducted each time the material changes.
At least one sample must be classi?ed in accordance with
ASTM 13?2487. Soils utilized during embankment con?
struction shall be described and identi?ed in accordance
with ASTM (Standard Practice for Descrip-
tion and Identi?cation of Soils (Visual-Manual Proce~
dure)). Soil identi?cation and description in accordance

BULLETIN, VOL. 46, NO. 41, OCTOBER 3, 2016

6496 RULES AND REGULATIONS

with this procedure shall be performed at a minimum
rate of one sample per 1,000 cubic yards of placed ?ll.
Results of testing of materials shall be provided to the
Department upon request.

(6) The embankment must be constructed out of soils
designated ML, only. Soils
with split designations when one of the designations used. Soils
muet contain a minimum of 20% of No. 200 sieve
materials or larger. Results of testing of materials shall
be provided to the Department upon request.

(7) Particles greater than 6 inches in any dimension
may not be used for embankment construction.

(8) Soil used in embankment construction must be
compacted. Soil compaction shall be conducted in accord?
ance with the following:

Compaction shall be conducted with a sheepsfoot or
pad roller.

(ii) The maximum loose lift thickness must be 9 inches.

Soil shall be compacted until visible nonmovement
of the embankment material.

(iv) Soil shall be compacted to a minimum of 95% of
the standard proctor in accordance with ASTM D698
(Standard Test Methods for Laboratory Compaction Char-
acteristics of Soil Using Standard Effort). Satisfactory
compaction shall be veri?ed by ?eld density testing in
accordance with ASTM D1556 (Standard Test Method for
Density and Unit Weight of Soil in Place by the Sand
Cone Method) or ASTM D6938 (Standard Test Method for
In?Place Density and Water Content of Soil and Soil?
Aggregate by Nuclear Methods (Shallow Depth)) with a
minimum of one test per 2,000 square yards of lift surface
and at least one test per lift.

(9) Exposed embankment slopes shall be permanently
stabilized using one or a combination of the following
methods:

Exposed embankments shall be limed, fertilized,
seeded and mulched, and permanent vegetative ground
covering in compliance with 102.22 (relating to site
stabilization) shall be established upon completion of
construction of the impoundment.

(ii) Compacted rock ?ll or riprap placed on the down-
stream face of the embankment as a cover having a
minimum depth of 2 feet. The rock ?ll must be durable,
evenly distributed and underlain by a Class 2, Type A
geotextile.

The owner or operator may request approval ?'om
the Department to deviate from the requirements in this
section. The request must demonstrate that the alternate
practice provides equivalent or superior protection to the
requirements of this section. I

783.591). Well development impoundments.

In addition to meeting the requirements of
78a.59a (relating to impoundment embankments), any
new well development impoundments must be in compli-
ance with this section.

A well operator using a well development impound?
ment prior to October 8, 2016, shall register the location
of the well development impoundment by December 7,
2016, by providing the Department, through the Depart-
ment?s web site, with electronic noti?cation of the GPS
coordinates, township and county where the well develop-
ment impoundment is located as well as certi?cation as to
whether the impoundment meets the requirements in

subsections and Any impoundments that do
not comply with the requirements in subsections 
and shall be upgraded to meet these requirements or
restored in accordance with subsection by October 10,
2017.

A well operator shall register the location of a new
well development impoundment prior to construction.
Registration of the well development impoundment may
be transferred to another operator. Registration transfers
shall utilize forms provided by the Department and be
submitted electronically to the Department through its
web site.

Well development impoundments shall be con-
structed with a impervious liner.

Unless an individual is continuously present at a
well development impoundment, a fence must completely
surround the well development impoundment to prevent
unauthorized acts of third parties and damage caused by
wildlife.

The bottom of the impoundment must be at least 20
inches above the seasonal high groundwater table. The
applicant may maintain the required separation distance
of 20 inches by passive arti?cial means such as an
under?drain system throughout the lifetime of the im-
poundment. In no case shall the regional groundwater
table be affected by the passive arti?cial system. The
operator shall document the depth of the seasonal high
groundwater table, the manner in which the depth of the
seasonal high groundwater table was ascertained, the
distance between the bottom of the impoundment and the
seasonal high groundwater table, and the depth of the
regional groundwater table if the separation between the
impoundment bottom and seasonal high groundwater
table is maintained by arti?cial means. A soil scientist or
other similarly trained person using accepted and docu?
mented scienti?c methods shall make the determination.
The determination must contain a statement certifying
that the impoundment bottom is at least 20 inches above
the seasonal high groundwater table according to ob-
served ?eld conditions. The name, quali?cations and
statement of the person making the determination and
the basis of the determination shall be provided to the
Department upon request.

Well development impoundments shall be restored
by the operator that the impoundment is registered to
within 9 months of completion of hydraulic fracturing of
the last well serviced by the impoundment. An impoand?
ment is restored under this subsection by the operator
removing excess water and the liner, returning
the site to approximate original conditions, including
preconstruction contours, and supporting the land uses
that existed prior to oil and gas operations to the extent
practicable. An extension of the restoration requirement
may be approved under 78a.65(c) (relating to site
restoration). If requested by the landowner in writing, on
forms provided by the Department, the requirement to
return the site to approximate original contours may be
waived by the Department if the liner is removed from
the impoundment.

Prior to storing mine in?uenced water in a well
development impoundment, the operator shall develop a
mine in?uenced water storage plan and submit it to the
Department for approval.

(1) The mine in?uenced water storage plan shall be
submitted on forms provided by the Department and
include the following:

BULLETIN, VOL. 45, NO. 41, OCTOBER 8, 2016

RULES AND REGULATIONS 6497

A demonstration that the escape of the mine in?u?
enced water stored in the well development impoundment
will not result in air, water or land pollution, or endanger
persons or property.

(ii) A procedure and schedule to test the mine in?u~
enced water. This testing shall be conducted at the source
prior to storage in the impoundment.

A records retention schedule for the mine in?u-
enced water test results.

(2) An operator with an approved mine in?uenced
water storage plan shall maintain records of all mine
in?uenced water testing prior to storage. These records
shall be made available to the Department upon request.

The Department may require the operator to test
water sources proposed to be stored in a well development
impoundment prior to storage.

783.5913. Centralized impoundments.

An operator using a centralized impoundment as of
October 8, 2016, shall close the centralized impoundment
in accordance with this section or obtain a permit in
accordance with Subpart D, Article IX (relating to re?
sidual waste management). The closure plan shall be
submitted electronically to the Department through its
web site for review and approval no later than April 8,
2017. The operator shall properly close the centralized
impoundment in accordance with the approved plan or
obtain a permit in accordance with Subpart D, Article 1X
no later than October 8, 2019.

The closure plan must provide for the following:

(1) Removal of any impermeable membrane, concrete
and earthen liner so that water movement to subsoils is
achieved.

(2) Restoration of the site to approximate original

conditions, including preconstruction contours, and back-
?lling the impoundment to above ?nished grade to allow
for settlement of ?ll and so the impoundment will no
longer impound water.

(3) A plan for the removal of equipment, structures,
wastes and related material from the facility.

(4) An estimate of when ?nal closure will occur, includ?
ing an explanation of the basis for the estimate.

(5) A description of the steps necessary for closure of
the facility.

(6) A narrative description, including a schedule of
measures that are proposed to be carried out in prepara?
tion for closure and after closure at the facility, including
measures relating to the following:

Water quality monitoring including, but not limited
to, analyses of samples from the monitoring wells that
were installed at the time of the construction of the
centralized impoundment.

(ii) A soil sampling plan that explains how the operator
will analyze the soil beneath the impoundment?s liners.
Analysis shall be based on a grid pattern or other method
approved by the Department. Any spills or leaks detected
shall be reported and remediated in accordance with
78a.66 (relating to reporting and remediating spills and
releases) prior to impoundment closure.

Compliance with Chapter 102 (relating to erosion
and sediment control) including erosion and sediment
control and PCSM.

(iv) Access control, including maintenance of access
control.

(V) The name, address and telephone number at which
the operator may be reached.

783.60. Discharge requirements.

The owner and operator may not cause or allow a
discharge of a substance, ?ll or dredged material to the
waters of the Commonwealth unless the discharge com?
plies with this subchapter and Chapters 91, 92a, 93, 95,
102 and 105, The Clean Streams Law (35 RS. 691.1?
691.1001), the Dam Safety and Encroachments Act (32
RS. 6931?69827) and the act.

The owner and operator may not discharge tophole
water or water in a pit as a result of precipitation by land
application unless the discharge is in accordance with the
following requirements:

(1) No additives, drilling muds, regulated substances or
drilling ?uids other than gases or fresh water have been
added to or are contained in the water, unless otherwise
approved by the Department.

(2) The pH is not less than 6 nor greater than 9
standard units, or is characteristic of the natural back-
ground quality of the groundwater.

(3) The speci?c conductance of the discharge is less
than 1,000 umHos/cm.

(4) There is no sheen from oil and grease.

(5) The discharge water shall be spread over an undis?
turbed, vegetated area capable of absorbing the tophole
water and ?ltering solids in the discharge, and spread in
a manner that prevents a direct discharge to surface
waters and complies with 78a.53 (relating to erosion
and sediment control and stormwater management).

(6) Upon completion, the area complies with 78a.53.

(7) The area of land application is not within 200 feet
of a water supply or within 100 feet of a watercourse or
body of water or within the ?oodplain.

(8) If the water does not meet the requirements of
paragraph (2) or (4), the Department may approve treat-
ment prior to discharge to the land surface.

(0) Compliance with subsection shall be documented
by the operator and made available to the Department
upon request while conducting activities under subsection
and submitted under and (2) (relating
to site restoration).

7821.61. Disposal of drill cuttings.

Drill cuttings from above the surface casing seat#
pits. The owner or operator may dispose of drill cuttings
from above the surface casing seat determined in accord?
ance with 78a.83(c) (relating to surface and coal protec?
tive casing and cementing procedures) in a pit at the well
site if the owner or operator satis?es the following
requirements:

(1) The drill cuttings are generated from the well at
the well site.

(2) The drill cuttings are not contaminated with a
regulated substance, including brines, drilling muds,
stimulation ?uids, well servicing ?uids, oil, production
?uids, or drilling ?uids other than tophole water, fresh

water or gases.

(3) The disposal area is not within 100 feet of a
watercourse or body of water or within the ?oodplain.

(4) The disposal area is not within 200 feet of a water
supply.

BULLETIN, VOL. 46, N0. 41, OCTOBER 8, 2016

RULES AND REGULATIONS 6499

Prior to drainage of accumulated precipitation from
secondary containment, the secondary containment shall
be inspected and accumulations of oil picked up and
returned to the tank or disposed of in accordance with
approved methods.

After complying with subsection drainage of
secondary containment is acceptable if:

(1) The accumulation in the secondary containment
consists of only precipitation directly to the secondary
containment and drainage will not cause a harmful
discharge or result in a sheen.

(2) The secondary containment drain valve is opened
and rescaled, or other drainage procedure, as applicable,
is conducted under responsible supervision.

An owner or operator who installed a tank or tanks
with a combined capacity of at least 1,320 gallons prior to
October 8, 2016, to store condensate produced from a well
shall meet the requirements of this section when a tank
is replaced, refurbished or repaired or by October 9, 2018,
whichever is sooner.

'78a.64a. Secondary containment.

Well sites shall be designed and constructed using
secondary containment.

All regulated substances, including solid wastes and
other regulated substances in equipment or vehicles, shall
be managed within secondary containment. This subsec-
tion does not apply to fuel stored in equipment or vehicle
fuel tanks unless the equipment or vehicle is being
refueled at the well site.

Secondary containment must meet all of the follow-
mg:

(1) Secondary containment must be used on the well
site when any equipment that will be used for any phase
of drilling, casing, cementing, hydraulic fracturing or
?owback operations is brought onto a well site and when
regulated substances including drilling mud, drilling mud
additives, hydraulic oil, diesel fuel, hydraulic fracturing
additives or ?cwback are brought onto or generated at
the well site.

(2) Secondary containment must have a coef?cient of
permeability no greater than 1 10'1? cm/sec.

(3) The physical and chemical characteristics of all
liners, coatings or other materials used as part of the
secondary containment, that could potentially come into
direct contact with regulated substances being stored,
must be compatible with the regulated substance and be
resistant to physical, chemical and other failure during
handling, installation and use. Liner compatibility must
satisfy compatibility test methods as approved by the
Department.

Methods of secondary containment open to the
atmosphere must have storage capacity suf?cient to hold
the volume of the largest single aboveground primary
containment, plus an additional 10% of volume for pre-
cipitation. Using double walled tanks capable of detecting
a leak in the primary containment ful?ll the require
ments in this subsection. Tanks that are manifolded
together shall be designed in a manner to prevent the
uncontrolled discharge of multiple manifolded tanks.

All secondary containment shall be inspected
weekly to ensure integrity. If the secondary containment
is damaged or compromised, the well operator shall
repair the secondary containment as soon as practicable.
The well operator shall maintain records of any repairs
until the well site is restored. Stormwater shall be

removed as soon as possible and prior to the capacity of
secondary containment being reduced by 10% or more.

Regulated substances that escape from primary
containment or are otherwise spilled onto secondary
containment shall be removed as soon as possible. After
removal of the regulated substances the operator shall
inspect the secondary containment. If the secondary
containment did not completely contain the material, the
operator shall notify the Department and remediate the
affected area in accordance with 78a.66 (relating to
reporting and remediating spills and releases).

Stormwater that comes into contact with regulated
substances stored within the secondary containment shall
be managed as residual waste.

Inspection reports and maintenance records shall
be available at the well site for review by the Depart?
ment.

Documentation of chemical compatibility of second"
ary containment with material stored within the system
shall be provided to the Department upon request.

783.65. Site restoration.

(3.) Restoration. The owner or operator shall restore
land surface areas disturbed to construct the well site as
follows:

(1) Post-drilling. Within 9 months after completion of
chilling a well, the owner or operator shall undertake
post?drilling restoration of the well site in accordance
with a restoration plan developed in accordance with
subsection and remove all drilling supplies, equip-
ment, primary containment and secondary containment
not necessary for production or needed to safely operate

the well.

When multiple Wells are drilled or permitted to be
drilled on a single well site, post-drilling restoration is
required within 9 months after completion of drilling all
permitted wells on the well site or 9 months after the
expiration of all existing well permits on the well site,
whichever is later.

(ii) A drill hole or bore hole used to facilitate the
drilling of a well shall be filled with cement, soil,
uncontaminated drill cutl?ngs or other earthen material
before moving the drilling equipment from the well site.

Drilling supplies and equipment not needed for
production may only be stored on the well site if express
written consent of the surface landowner is obtained and
the supplies or equipment are maintained in accordance
with 78a.64a (relating to secondary containment).

(iv) The areas necessary to safely operate the well
include the following:

(A) Areas used for service vehicle and rig access.

(B) Areas used for storage tanks and secondary con?
tainment.

(C) Areas used for wellheads and appurtenant oil and
gas processing facilities.

(D) Areas used for any necessary safety buffer limited
to the area surrounding equipment that is physically
cordoned off to protect the facilities.

(E) Areas used to store any supplies or equipment
consented to by the surface landowner.

(F) Areas used for operation and maintenance of long-
term PCSM best management practices.

BULLETIN, VOL. 46, NO. 41, OCTOBER 8, 201B

6500 EU LES AND REGULATIONS

(2) Post-plugging. Within 9 months after plugging the
?nal well on the well site, the owner or operator shall
remove all production or storage facilities, supplies and
equipment and restore the well site to approximate
original conditions and restore stormwater runoff rate,
volume and quality to preconstruction condition in accord-
ance with 102.8 (relating to PCSM requirements).

(3) Wells not drilled. If a well site is constructed and
the well is not drilled, the well site shall be restored
within 9 months after the expiration of the well permit
unless the Department approves an extension for reasons
of adverse weather or lack of essential fuel, equipment or
labor.

Restoration plan. An operator of a well site shall
develop and implement a restoration plan. The restora-
tion plan must address:

(1) The restoration of areas not needed to safely oper-
ate the well to approximate original conditions.

(2) The proposed site con?guration after post?drilling
restoration including the areas of the well site being
restored.

(3) The minimization of impervious areas. Impervious
areas include, but are not limited to, areas Where soil has
been compacted, areas where soil has been treated with
amendments to ?rm or harden the soil, and areas
underlain with an impermeable liner.

(4) The removal of all drilling supplies and equipment
not needed for production, including primary and second-
ary containment.

(5) The manner in which the restoration of the dis?
turbed areas will achieve meadow in good condition or
better or otherwise incorporate ABACT or nondischarge
alternative PCSM best management practices (BEEP).

(6) PCSM BMPs remaining in place and proof of
compliance with 102.8(1) and or a licensed profes?
sional certi?cation of complete site restoration to approxi?
mate original contours and return to preconstruction
stormwater runoff rate, volume and quality in accordance
with The owner or operator shall remain
responsible for compliance with the terms of the restora?
tion plan including long-term operation and maintenance
of all PCSM BMIPS on the project site and is responsible
for any violations occurring on the project site, prior to
written approval of the final restoration report.

(7) The permanent stabilization of the restored areas
by either of the following:

In accordance with 102.22 (relating to site stabili?
zation).

(ii) Through implementation of PCSM BMPS as re?
quired under 102.8, including 

(8) An operator of a well site who is required to obtain
a permit under 102.5(0) (relating to permit require-
ments) may develop a written restoration plan containing
drawings and a narrative that address the requirements
of paragraphs to demonstrate compliance with


(0) Extension of drilling or production period. The
restoration period in this subsection may be extended
through approval by the Department for an additional
period of time, not to exceed 2 years.

. (1) A request to extend the restoration period shall be
submitted electronically on forms provided by the Depart?
ment through the Department?s web site not more than 6
months after the completion of drilling.

(2) The request must specify the reasons for the re-
quest to extend the restoration period not to exceed 24
months. The request must include a justi?cation for the
length of extension and demonstrate that either:

The extension will result in less earth disturbance,
increased water reuse or more ef?cient development of
the resources.

(ii) Restoration cannot be achieved due to adverse
weather conditions or a lack of essential fuel, equipment
or labor.

(3) A demonstration that the extension will result in
less earth disturbance, increased water reuse or more
ef?cient development of the resources must include the
following:

A demonstration that the site is stabilized and the
BMPs utilized on the well site Will address PCSM.

(ii) A demonstration that the portions of the well site
not occupied by production facilities or equipment will be
returned to approximate original conditions.

Areas not restored. Disturbed areas associated with
well sites that are not included in a restoration plan, and
other remaining impervious surfaces, must comply with
all requirements in Chapter 102 (relating to erosion and
sediment control). The PCSM plan provisions in
102.8(n) apply only to the portions of the restoration
plan that provide for restoration of disturbed areas to
meadow in good condition or better or otherwise incorpo-
rate ABACT or nondischarge PCSM BMPS.

Post-drilling restoration reports. Within 60 calendar
days after post?drilling restoration under subsection
the operator shall submit a restoration report to
the Department. The well operator shall forward a copy of
all restoration reports to the surface landowner. The
report shall be made electronically on forms provided by
the Department through the Department?s web site and
must identify the following:

(1) The date of land application of the tophole water.

(2) The results of pH and speci?c conductance tests
and an estimated volume of discharge.

(3) The method used for disposal or reuse of the free
liquid fraction of the waste, and the name of the hauler
and disposal facility, if any.

(4) The location, including GPS coordinates, of the pit
in relation to the well, the depth of the pit, the type and
thickness of the material used for the pit subbase, the
type and thickness of the pit liner, the type and nature of
the waste, the type of any approved solidi?er, a descrip?
tion of the pit closure procedures used and the pit
dimensions.

(5) The location of the area used for land application of
the waste, and the results of a chemical analysis of the
waste soil mixture if requested by the Department.

(6) The types and volumes of waste produced and the
name and address of the waste disposal facility and waste
hauler used to dispose of the waste.

(7) The name, qualifications and basis for determina?
tion that the bottom of a pit used for encapsulation is at
least 20 inches above the seasonal high groundwater
table.

Post-plugging restoration reports. Within 60 calen-
dar days after post-plugging restoration under subsection
the operator shall submit a restoration report to
the Department. The well operator shall forward a copy of
all restoration reports to the surface landowner. The

BULLETIN, VOL. 46, no. 41, a, 2015

 

 LES AND REGULATIO NS 5501

report shall be made electronically on forms provided by
the Department through the Department?s web site and
must include the following:

(1) A description of the types and volumes of waste
produced, and the name and address of the waste dis-
posal facility and waste hauler used to dispose of the
waste.

(2) Con?rmation that earth disturbance activities, site -

restoration including an installation of any PCSM BMPs
and permanent stabilization in accordance with 102.22
have been completed.

Written consent. Written consent of the landowner
on forms provided by the Department satis?es the resto~
ration requirements of this section provided the operator
develops and implements a site restoration plan that
complies with subsections and and all
PCSM requirements in Chapter 102.

783.66. Reporting and remediating spills and re-
leases.

Scope. This section applies to reporting and
remediating Spills or releases of regulated substances on
or adjacent to well sites and access roads.

Reporting releases.

(1) An operator or other responsible party shall report
the following spills and releases of regulated substances
to the Department in accordance with paragraph (2):

A spill or release of a regulated substance causing or
threatening pollution of the waters of the Commonwealth
in the manner required under 91.33 (relating to inci?
dents causing or threatening pollution).

(ii) A spill or release of 5 gallons or more of a regulated
substance over a 24-hour period that is not completely
contained by secondary containment.

(2) In addition to meeting the noti?cation requirements
of 91.33, the operator or other responsible party shall
contact the appropriate regional Department of?ce by
telephone or call the Department?s Statewide toll free
number as soon as practicable, but no later than 2 hours
after discovering the spill or release. To the extent known,
the following information shall be provided:

The name of the person reporting the spill or release
and telephone number where that person can be reached.

(ii) The name, address and telephone number of the
operator or other responsible party.

The date and time of the spill or release or when it
was discovered.

(iv) The lecation of the spill or release, including
directions to the site, GPS coordinates or the 9?1?1
address, if available.

A brief description of the nature of the spill or
release and its cause, what potential impacts to public
health and safety or the environment may exist, including
any available information concerning the pollution or
threatened pollution of surface water, groundwater or
soil.

(vi) The estimated weight or volume of each regulated
substance spilled or released.

(vii) The nature of any injuries.
Remedial actions planned, initiated or completed.

(3) The operator or other responsible party shall take
necessary interim corrective actions to prevent:

The regulated substance from polluting or threaten-
ing to pollute the waters of the Commonwealth.

(ii) Damage to property.

Impacts to users of waters of the
Commonwealth.

(4) The operator or other responsible party shall iden?
tify and sample water supplies that have been polluted or
for which there is a potential for pollution in a reasonable
and systematic manner. The operator or other responsible
party shall restore or replace a polluted water supply in
accordance with 78a.51 (relating to protection of water
supplies). The operator or other responsible party shall
provide a copy of the sample results to the water supply
owner and the Department within 5 business days of
receipt of the sample results from the laboratory.

(5) The Department may immediately approve tempo?
rary emergency storage or transportation methods neces-
sary to prevent or mitigate harm to the public health,
safety or the environment. Storage may be at the site of
the incident or at a site approved by the Department.

(6) After responding to a spill or release, the operator
or other responsible party shall decontaminate equipment
used to handle the regulated substance, including storage
containers, processing equipment, trucks and loaders,
before returning the equipment to service. Contaminated
wash water, waste solutions and residues generated from
washing or decontaminating equipment shall be managed
as residual waste.

(0.) Remediating releases. Remediation of an area pol-
luted by a spill or release is required. The operator or
other responsible party shall remediate a release in
accordance with the following:

(1) Spills or releases to the ground of less than 42
gallons at a well site that do not pollute or threaten to
pollute waters of the Commonwealth may be remediated
by removing the soil visibly impacted by the spill or
releasa and properly managing the impacted soil in
accordance with the Department?s waste management
regulations. The operator or responsible party shall notify
the Department of its intent to remediate a spill or
release in accordance with this paragraph at the time the
report of the spill or release is made.

(2) For spills or releases to the ground of greater than
or equal to 42 gallons or that pollute or threaten to
pollute waters of the Commonwealth, the operator or
other responsible person must demonstrate attainment of
one or more of the standards established by Act 2 and
Chapter 250 (relating to administration of Land Recycling
Program) in the following manner:

Within 15 business days of the spill or release, the
operator or other responsible party shall provide an
initial written report that includes, to the extent that the
information is available, the following:

(A) The regulated substance involved.

(B) The location where the spill or release occurred.
(C) The environmental media affected.

(D) Pollution or threatened pollution of water supplies.
(E) Impacts to buildings or utilities.

(F) Interim remedial actions planned, initiated or com~
pleted.

(G) A summary of the actions the operator or other
responsible party intends to take at the site to address
the spill or release such as a schedule for site character~

BULLETIN, VOL. 46, NO. 41, OCTOBER 8, 2016

6502 RULES AND REGULATIONS

ization, to the extent known, and the anticipated time
frames within which it expects to take those actions.

(ii) After the initial report, any new pollution or other
impacts identi?ed or discovered during interim remedial
actions or site characterization shall also be reported in
writing to the Department within 15 business days of
their discovery.

Within 180 calendar days of the spill or release,
the operator or other responsible party shall perform a
site characterization to determine the extent and magni-
tude of the pollution and submit a site characterization
report to the appropriate Department regional of?ce
describing the ?ndings. The time to submit the site
characterization report may be extended by the Depart?
ment. The report must include a description of any
interim remedial actions taken. 

(iv) The report under subparagraph may be consid-
ered to be a ?nal remedial action completion report if the
interim remedial actions meet all of the requirements of
an Act 2 cleanup standard.

If the site characterization indicates that the in?
terim remedial actions taken did not adequately remediw
late the spill or release, the operator or other responsible
party shall develop and submit a remedial action plan to
the appropriate Department regional o?ice for approval.
The plan is due within 45 calendar days of submission of
the site characterization to the Department. Remedial
action plans must contain the elements outlined in
245.311(a) (relating to remedial action plan), as well as
a schedule for the submission of remedial action progress
reports.

(vi) Within 45 days after the selected remediation
standard has been attained, the operator or other respon?
sible party shall submit a remedial action completion
report to the appropriate Department regional of?ce for
approval. Remedial action completion reports shall con?
tain the elements outlined in 245.313(b) (relating to
remedial action completion report).

783.67. Borrow pits.

An operator who owns or controls a borrow pit that
does not require a permit under the Noncoal Surface
Mining Conservation and Reclamation Act (52 RS.
3301~?3326) under the exemption in section 3273.1(b)
of the act (relating to relationship to solid waste and
surface mining), because the borrow pit is used exclu?
sively for extraction of minerals for the purpose of oil and
gas well development, including access road construction,
shall operate, maintain and reclaim the borrow pit in
accordance with the performance standards in Chapter
77, Subchapter I (relating to environmental protection
performance standards) and in accordance with Chapter
102 (relating to erosion and sediment control), and other
applicable laws. The mining permit exemption only ap-
plies so long as the borrow pit is servicing an oil and gas
well site where a well is permitted under section 3211 of
the act (relating to well permits) or registered under
section 82.13 of the act (relating to well registration and
identi?cation) and the requirements of section 3225 of the
act (relating to bonding) are satis?ed by ?ling a surety or
collateral bond for wells drilled on or after April 18, 1985.
Borrow pits shall be subject to The Clean Streams Law
(35 RS. and regulations promul-
gated thereunder, including Chapter 102. For purposes of
determining permitting requirements under 102.5(0)
(relating to permit requirements), areas subject to the
mining permit exemption shall be considered part of the
project along with the well site being serviced.

Operators shall register the location of their exist?
ing borrow pits by December 7, 2016, by providing the
Department, electronically, through the Department?s web
site, with the GPS coordinates, township and county
where the borrow pit is located. The operator shall
register the location of a new borrow pit in the same
manner prior to construction.

Borrow pits used for the development of oil and gas
well sites and access roads that no longer meet the
conditions under section 3273.1 of the act must meet one
of the following:

(1) Be restored within 9 months after completion of
drilling the ?nal well on a well site serviced by the
borrow pit or 9 months after the expiration of all well
permits on well sites serviced by the borrow pit, which
ever occurs later. An extension of the restoration require?
ment may be approved under 78a.65(c) (relating to site
restoration).

(2) Obtain a noncoal surface mining permit for its
continued use, unless relevant exemptions apply under
the Noncoal Surface Mining Conservation and Reclama?
tion Act and regulations promulgated thereunder.

A well operator who owns or operates a borrow pit
constructed prior to October 8, 2016, shall have the
borrow pit inspected by a quali?ed person for compliance
with the requirements of this section prior to April 6,
2017. Any borrow pits that do not comply with subsection
shall be upgraded to meet the requirements of this
section or restored by October 10, 2017.

78.91.68. Oil and gas gathering pipelines.

The requirements of this section apply to all earth
disturbance activities associated with oil and gas gather-
ing pipeline installations and supporting facilities includ-
ing the construction right-of-way, work space areas, pipe
storage yards, borrow and disposal, areas, access roads
and other necessary areas identi?ed on the erosion and
sediment control plan. The construction, installation, use,
maintenance, repair and removal of oil and gas gathering
pipelines under this section shall be conducted in accord?
ance with Chapters 102 and 105 (relating to erc'asion and
sedirrient control; and dam safety and waterway manage-
ment .

Highly visible ?agging, markers or signs shall be
used to identify the shared boundaries of the limit of
disturbance, wetlands and locations of threatened or
endangered species habitat prior to land clearing. The
?agging, markers or signs shall be maintained through?
out earth disturbance activities and restoration or PCSM
activities.

The operator shall maintain topsoil and subsoil
during excavation under the following, unless otherwise
authorized by the Department:

(1) Topsoil and subsoil must remain segregated until
restoration.

(2) Topsoil and subsoil must be prevented from enter"
ing watercourses and bodies of water.

(3) Topsoil cannot be used as bedding for pipelines.

(4) Native topsoil and imported topsoil must be of
equal or greater quality to ensure the land is capable of
supporting the uses that existed prior to earth disturu
bance.

Back?lling of the gathering pipeline trench shall be

conducted in a manner that minimizes soil compaction at
the surface to ensure that water in?ltration will be

BULLETIN, VOL. 46, NO. 41, OCTOBER 8, 2016

 

 

6506 RULES AND REGULATIONS

used in wells drilled below the Onondaga formation or
where blow?out preventers are required.

7823.72. Use of safety devices?blow-out preven~
tion equipment.

The operator shall use blow-out prevention equip?
ment after setting casing with a competent casing seat in
the following circumstances:

(1) When drilling a well that is intended to produce
natural gas from an unconventional formation.

(2) When drilling out solid core hydraulic fracturing
plugs to complete a well.

(3) When well head pressures or natural open ?ows are
anticipated at the well site that may result in a loss of
well control.

(4) When the operator is drilling in an area where
there is no prior knowledge of the pressures or natural
open ?ows to be encountered.

(5) 0n wells regulated by the Oil and Gas Conservation
Law (58 RS. 401?419).

(6) When drilling within 200 feet of a building.

Blow?out prevention equipment used must be in
good working condition at all times.

Controls for the blow?out preventer shall be acces-
sible to allow actuation of the equipment. Additional
controls for a blow?out preventer with a pressure rating of
greater than 3,000 psi, not associated with the rig
hydraulic system, shall be located at least 50 feet away
from the drilling rig so that the blow-out preventer can be
actuated if control of the well is lost.

The operator shall use pipe ?ttings, valVes and
unions placed on or connected to the blow?out prevention
systems that have a working pressure capability that
exceeds the anticipated pressures.

The operator shall conduct a complete test of the
ram type blow-out preventer and related equipment for
both pressure and ram operation before placing it in
Service on the well. The operator. shall test the annular
type blow-out preventer in accordance with the manufac-
turer?s published instructions, or the instructions of a
professional engineer, prior to the device being placed in
service. Blow-out prevention equipment that fails the test
may not be used until it is repaired and passes the test.

When the equipment is in service, the operator shall
visually inspect blow?out prevention equipment during
each tour of drilling operation and during actual drilling
operations test the pipe rams for closure daily and the
blind rams for closure on each round trip. When more
than one round trip is made in a day, one daily closure
test for blind rams is suf?cient. Testing shall be con?
ducted in accordance with American Petroleum Institute
publication API BP53, Recommended Practice for
Blowout Prevention Equipment Systems for Drilling
Wells,? or other procedure approved by the Department.
The operator shall record the results of the inspection and
closure test in the drillers log before the end of the tour.
If blow-out prevention equipment is not in good working
order, drilling shall cease when cessation of drilling can
be accomplished safely and not resume until the blow-out
prevention equipment is repaired or replaced and re-
tested.

All lines, valves and ?ttings between the closing
unit and the blow?out preventer stack must be ?ame

resistant and have a rated working pressure that meets
or exceeds the requirements of the blow?out preventer
system.

When a blowout preventer is installed or required
under subsection there shall be present on the well
site an individual with a current certi?cation from a well
control course accredited by the International Association
of Drilling Contractors or other organization approved by
the Department. The certi?cation shall be available for
review at the well site. The Department will maintain a
list of approved accrediting organizations on its web site.

Well drilling and completion operations requiring
pressure barriers, as identi?ed by the operator under
78a.55(d) (relating to control and disposal planning;
emergency responsa for unconventional wells), shall emu
ploy at least two mechanical pressure barriers between
the open producing formation and the atmosphere that
are capable of being tested. The mechanical pressure
barriers shall be tested according to manufacturer speci??
cations prior to operation. If during the course of opera-
tions the operator only has one functioning barrier,
operations shall cease until additional barriers are added
and tested or the redundant barrier is repaired and
tested. Stripper rubber or a stripper head may not be
considered a barrier.

A coiled tubing rig or a hydraulic workover unit
with appropriate blowout prevention equipment shall be
employed during post-completion cleanout operations in
horizontal unconventional formations.

The minimum amount of intermediate casing that
is cemented to the surface to which blow-out prevention
equipment may be attached shall be in accordance with
the following:

Minimum Cemented

Casing Required
Proposed Tbtal 1l/lerticonl (in feet of
Depth (in feet) casing cemented)
Up to 5,000 400
5,001 to 5,500 500
5,501 to 0,000 600
6,001 to 6,500 700
6,501 to 7,000 800
7,001 to 8,000 1,000
8,001 to 9,000 1,200
9,001 to 10,000 1,400
Deeper than 10,000 1,800

(1) Upon completion of the drilling operations at a well,
the operator shall install and utilize equipment, such as a
shut-off valve of suf?cient rating to contain anticipated
pressure, lubricator or similar device, as may be neces-
sary to enable the well to be effectively shut-in while
logging and servicing the well and after completion of the
Well.

7 321.73. General provision for Well constructiou
and operation.

The operator shall construct and operate the well in
accordance with this chapter and ensure that the integ-
rity of the well is maintained and health, safety, environ-
ment and property are protected.

The operator shall prevent gas, oil, brine, comple?
tion and servicing ?uids, and any other ?uids or materi?
als from below the casing seat from entering fresh

BULLETIN, VOL. 46, NO. 41, OCTOBER 8, 2016

RU LES AND REGULATIONS 6507

groundwater, and shall otherwise prevent pollution or
diminution of fresh groundwater.

The operators of active, inactive, abandoned, and
plugged and abandoned wells identi?ed as part of an area
of review survey conducted under 78a.52a (relating to
area of review) that likely penetrate within 1,500 feet
measured vertically from the stimulation perforations, if
known, shall be noti?ed. Notice shall be provided at least
30 days prior to the start of drilling the well or at the
time the permit application is submitted to the Depart?
ment if the start of drilling is planned less than 30 days
from the date of permit issuance. Orphan wells, aban-
doned wells, and plugged and abandoned wells idenij?ed
as part of an area of review survey conducted under
78a.52a that either penetrate within 1,500 feet mea-
sured vertically from the stimulation perforations or have
an unknown true vertical depth shall be visually moni-
tored during stimulation activities. The operator shall
immediately notify the Department of any change to a
well being monitored, of any treatment pressure or
volume changes indicative of abnormal fracture propaga-
tion at the well being stimulatedlor if otherwise made
aware of a con?rmed well communicaiion incident associ-
ated with their stimulation activities. Notice shall be
provided to the Department electronically through the
Department?s web site. In an event such as this, the
operator shall cease stimulating the well that is the
subject of the area of review survey and take action to
prevent pollution of waters of the Commonwealth or
discharges to the surface. The operator may not resume
stimulation of the well that is the subject of the area of
review survey without Department approval.

An operator that alters an orphan well, or an
abandoned well or plugged and abandoned well by hy-
draulic fracturing shall plug the altered well in accord?
ance with this chapter, or the operator may adopt the
altered well and place it into production.

After a well has been completed, recompleted, re?
conditioned or altered the operator shall prevent surface
shut-in pressure and surface producing back pressure
inside the surface casing or coal protective casing from
exceeding the following pressure: 80% multiplied by 0.433
psi per foot multiplied by the casing length (in feet) of the
applicable casing.

After a well has been completed, recompleted, recon?
ditioned or altered, if the surface shut?in pressure or
surface producing back pressure exceeds the pressure as
calculated in subsection the operator shall take action
to prevent the migration of gas and other ?uids from
lower formations into fresh groundwater. To meet this
standard the operator may cement or install on a packer
suf?cient intermediate or production casing or take other
actions approved by the Department. This section does
not apply during testing for mechanical integrity in
accordance with State or Federal requirements.

Excess gas encountered during drilling, completion
or stimulation shall be ?ared, captured or diverted away
from the drilling rig in a manner that does not create a
hazard to the public health or safety.

The well must be equipped with a check valve to
prevent back?ow from the pipelines into the well.

78a.74. Venting of gas.

The venting of gas to the atmOSphere from a well is
prohibited when the venting produces a hazard to the
public health and safety.

7821.75. Alternative methods.

A well operator may request approval from the
Department to use an alternative method or material for
the casing, plugging or equipping of a well under section
3221 of the act (relating to alternative methods).

Awell operator seeking approval under this section
shall ?le an application with the Department on forms
furnished by the Department. The application must:

(1) Describe the proposed alternative method or mate?
rial, in reasonable detail.

(2) Indicate the manner in which the alternative will
satisfy the goals of the act and this chapter.

Include a drawing or schematic of the alternative
method, if appropriate.

The well operator shall notify all coal owners and
operators and gas storage operators of record of the
proposal, by certi?ed mail. The well operator shall state
in the application that he has sent the certi?ed mail
notice to the coal owners and operators and gas storage
operators of record, either simultaneously with or prior to
submitting the proposal to the Department.

The coal owners and operators and gas storage
operators of record shall have up to 15 days from their
receipt of the no?ce to ?le objections or to indicate
concurrence with the proposed alternative method or
material.

If no objections are ?led within 15 days from receipt
of the notice, and if none are raised by the Department,
the Department will make a determination whether to
allow the use of the proposed alternative method or
material. -

7821.753. Area of alternative methods.

A well operator may request approval from the
Department to use an alternative method or material for
the casing, plugging or equipping of a well under section
3221 of the act (relating to alternative methods).

To establish an area of alternative methods, the
Department will publish a notice in the 
Bulletin of the proposed area of alternative methods and
provide the public with an opportunity to comment on the
proposal. After reviewing any comments received on the
proposal, the Department will publish a ?nal designation
of the area and required alternative methods in the
Bulletin.

Wells drilled within an area of alternative methods
established under subsection must meet the require-
ments speci?ed by the Department unless the operator
obtains approval from the Department to drill, operate or
plug the well in a different manner that is at least as safe
and protective of the environment as the requirements of
the area of alternative methods.

7821.76. Drilling within a gas storage reservoir
area.

An operator proposing to drill a well within a gas
storage reservoir area or a reservoir protective area shall
forward by certi?ed mail a copy of the well location plat,
the drilling, casing and cementing plan, and the antici-
pated date drilling will start to the gas storage reservoir
operator and to the Department for approval by the
Department and shall submit proof of noti?cation to the
gas storage reservoir operator to the Department with the
well permit application.

The storage operator may ?le an objection with the
Deparimnent to the drilling, casing and cementing plan or

BULLETIN, VOL. 46, N0. 41, OCTOBER 8, 2016

6518 RULES AND REGULATIONS

approval of inactive status), as appropriate. For a well
that was not drilled in accordance with the casing and
cementing standards, the wells shall be monitored in
accordance with 'Ib qualify for continued
inactive status, the owner or operator shall demonstrate,
by the data in the monitoring reports, that the condition
of the well continues to satisfy the requirements of
7851.102. The owner or operator shall submit the report
by March 31 of the following year.

78a.104. Term of inactive status.

Approval of inactive status for a well is valid for 5
years unless revoked. After 5 years, the owner or operator
shall plug or return to active status a well granted
inactive status unless the Department grants an applica-
tion for a 1-year extension. The operator of a well granted
inactive status may apply for renewal of inactive status
by demonstrating that the well con?nues to satisfy the
conditions imposed on the well by 78a.102 and 78a.103
(relating to criteria for approval of inactive status; and
annual monitoring of inactive wells).

7821.105. Revocation of inactive status.

The Department may revoke inactive status and may
order the immediate plugging of a well if one of the
following applies:

(1) The well is in violation of the act or regulations
administered by the Department.

(2) The operator of the inactive well has become insol-
vent, to the extent that the plan provided under
78a.102 (relating to criteria for approval of inactive
status) is no longer viable to return the well to active
status, or the operator otherwise demonstrates a lack of
ability or intention to comply with applicable laws and
regulations.

(3) The condition of the well no longer satis?es the
requirements of section 3214. of the act (relating to
inactive status) and ?78a.102 and 78a.103 and
78a.104 (relating to annual monitoring of inactive wells;
and term of inactive status).

(4) rThe owner or Operator is unwilling or unable to
perform his obligations under the act.

RADIOACTIVE LOGGING SOURCES
7851.111. Abandonment.

The owner or operator may not abandon a radioac?
tive source licensed by the Commonwealth for logging
purposes without consent of the Department. Approval of
a plan of abandonment may be arranged with the Depart?
ment by telephone and is to be followed by a written
report to the Department within 30 days after abandon?
ment of the radioactive source. The plan shall be ap?
proved by the Department.

The operator shall notify the Department of his
intention to leave a radioactive source in a well.

The operator shall mechanically equip a well in
which a radioactive source is abandoned to prevent the
accidental or intentional mechanical disintegration of the
radioactive source.

(1) The operator shall cover the radioactive source
being abandoned in the bottom of a well with a substan?
?al standard color-dyed cement plug on top of which a
mechanical stop or de?ector shall be set. The dye must
contrast with the color of the formation to alert a re-entry
operator prior to encountering the source.

(2) In a well where a logging source has been cemented
in place behind a casing string and above total depth,

upon plugging the well, a color-dyed cement plug shall be
placed opposite the abandoned source inside the well bore
and a mechanical stop or de?ector shall be placed on top
of the plug.

(3) If, after expending a reasonable effort, the operator
cannot comply with paragraph (1) or (2.) because of hole
the operator shall request Department ap;
proval to cease efforts to comply with paragraph (1) or (2)
and shall obtain approval for an alternate method for
abandoning the source and plugging the well.

Upon plugging a well in which a radioactive source
is left in the hole, the operator shall place a permanent
plaque by welding, bolting or cementing it to the top of
the bore hole in a manner approved by the Department
that re-entry cannot be accomplished without disturbing
the plaque. The plaque shall serve as a visual warning to
a person re?entering the hole that a radioactive source
has been abandoned in-place in the well. The plaque shall
depict the trefoil radiation symbol with the words ?Cau-
tion, Radioactive Material? under 10 CFR 20.1901(a)
(relating to caution signs.) and must be constructed of a
long?lasting material such as monel, stainless steel,
bronze or brass. The marker must bear the following
information:

(1) Farm name.
(2) Permit number.
(3) Name and address of operator.

(4) The type and strength of radioactive material aban~
doned in the well.

(5) The total well depth.
(6) Depth at which the source was abandoned.

(7) A warning not to drill below the plug?back depth or
to enlarge the casing.

(8) The date the source was abandoned.

Prior to workover or reaentry activity, if a radioac?
tive source is present, the operator shall have the plan of
operation approved by the Department before the
workover or re-entry is permitted.

This section does-not relieve the licensee, owner or
operator from the obligation to comply with Federal
regulations and this title, including Chapters 225 and 226
(relating to radiation safety requirements for industrial
radiographic operations; and licenses and radiation safety
requirements for well logging).

Subchapter E. WELL REPORTING

Sec.

7821.121. Production reporting.

7821.122. Well record and completion report.
7851.123. Logs and additional data.

7851.124. Certi?cate of plugging.

7811.121. Production reporting.

Each operator of an unconventional well shall sub-
mit a production and status report for each well
on an individual basis within 45 calendar days of the
close of each reporting period. Production shall
be reported for the preceding reporting period. When the
production data is not available to the operator on a well
basis, the operator shall report production on the most
well?speci?c basis available.

The production report must include infor?
mation on the amount and type of waste produced and
the method of waste disposal or reuse, including the
speci?c facility or well site where the waste was man?
aged. Waste information submitted to the Department in

BULLETIN, VOL. 46, NO. 41, OCTOBER 8, 201B

RULES AND REGULATIONS 6519

accordance with this subsection is deemed to satisfy the
residual waste biennial reporting requirements of
287.52 (relating to biennial report). 

The production report shall be submitted electroniu
cally to the Department through its web site.
7851.122. Well record and completion report.

For each well that is drilled or altered, the operator
shall keep a detailed drillers log at the well site available
for inspection until drilling is completed. Within 30
calendar days of cessation of drilling or altering a well,
the well operator shall submit a well record to the
Department on a form provided by the Department that
includes the following information:

(1) Name, address and telephone number of the per?
mittee.

(2) Permit number, and farm name and number.
(3) Township and county.

(4) Date drilling started and completed.

(5) Method of drilling.

(6) Size and depth of conductor pipe, surface casing,
coal protective casing, intermediate casing, production
casing and borehole.

(7) Type and amount of cement and results of cement"
ing procedures.

(8) Elevation and total depth.

(9) Drillers log that includes the name and depth of
formations from the surface to total depth, depth of oil
and gas producing zone, depth of fresh water and brines
and source of information.

(10) Certi?cation by the operator that the well has
been constructed in accordance with this chapter and any
permit conditions imposed by the Department.

(11) Whether methane was encountered other than in a
target formation.

(12) The country of origin and manufacture of tubular
steel products used in the construction of the well.

(13) The borrow pit used for well site development, if
any.

(14) Other information required by the Department.

Within 30 calendar days after completion of the
well, when the well is capable of production, the well
operator shall arrange for the submission of a completion

report to the Department on a form provided by the
Department that includes the following information:

(1) Name, address and telephone number of the per?
mittee. -

(2) Name, address and telephone number of the service
compames.

(3) Permit number, and farm name and number.

(4) and county.

(5) Perforation record.

(6) Stimulation record which includes the following:

A deScriptive list of the chemical additives in the
stimulation ?uid, including any acid, biocide, breaker,
brine, corrosion inhibitor, crosslinlrer, demulsi?er, friction
reducer, gel, iron control, oxygen scavenger, pH adjusting
agent, proppant, scale inhibitor and surfactant.

(ii) The percent by mass of each chemical additive in
the stimulation ?uid.

The trade name, vendor and a brief descriptor of
the intended use or function of each chemical additive in
the stimulation ?uid.

(iv) A list of the chemicals intentionally added to the
stimulation ?uid, by name and chemical abstract service
number.

The maximum concentration, in percent by mass, of
each chemical intentionally added to the stimulation
?uid.

(vi) The total volume of the base ?uid.

(vii) A list of water sources used under an approved
WW and the volume of water used from each source.

The total volume of recycled water used.
(ix) The pump rate and pressure used in the well.

(7) Actual open ?ow production and shut in surface
pressure.

(8) Open flow production and shut in surface pressure,
measured 24 hours after completion.

(9) The well development impoundrnent, if any, used in
the development of the well.

(10) Certi?cation by the operator that the monitoring
plan required under 7 8a.52a (relating to area of review)
was conducted as outlined in the area of review report.

When the well operator submits a stimulation re?
cord, it may designate speci?c portions of the stimulation
record as containing a trade secret or con?dential propri-
etary information. The Department will prevent disclo?
sure of the designated con?dential information to the
extent permitted under the Right-to-Know Law (65 RS.
or other applicable State law.

The well record required under subsection and
the completion report required under subsection shall
be submitted electronically to the Department through
the Department?s web site.

78a.123. Logs and additional data.

The well operator shall, within 90 days of comple~
tion or recompletion of drilling, submit a copy of any
electrical, radioactive or other standard industry legs
which have been run.

In addition, if requested by the Department within
1 year of the completion or recompletion of drilling, the
well operator shall file with the Department a copy of the
drill stem test charts, formation water analysis, porosity,
permeability or ?uid saturation measurements, core
analysis and lithologic log or sample description or other
similar data as compiled. Information is not required
unless the operator has had the information described in
this subsection compiled in the ordinary course of busi-
ness. Interpretation of the data is not required to be ?led.

Upon noti?cation by the Department prior to drill?
ing, the well operator shall collect additional data speci-
?ed by the Department, such as representative drill
cuttings and samples from cores taken, and other geologin
cal information that the operator can reasonably compile.
Interpretation of the data is not required to be ?led.

Data requested by the Department under subsec?
tions and shall be retained by the well operator
and ?led with the Department no more than 3 years after
completion of the well. Upon request for good cause, the
Department may extend the deadline up to 5 years from
the date of completion or recompletion of drilling the well.
The Department may request submission of the informa?

BULLETIN, VOL. 45, NO. 41, OCTOBER 8, 2016

 

Petition - Ex. 

 

 

 

 

 

 

 

 

INDEPENDENT REG ULA TOR 
REVIEW COWSSION
(1) Agency
Department of Environmental Protection
(2) Agency Number:
Identi?cation Number: #7484 IRRC Number: 3042

 

 

(3) PA Code Cite: 25 Pa. Code Chapters 78 and 78a

 

(4) Short Title:
Environmental Protection Performance Standards at Oil Gas Well Sites

 

(5) Agency Contacts (List Telephone Number and Email Address):
Primary Contact: Laura Edinger (717) 783~8727, ledinger@pa.gov
Secondary Contact: Jessica Shirley (717) 783-8727, jesshirley@pa.gov

 

(6) Type of Rulemaldng (check applicable box):

Proposed Regulation I: Emergency Certi?cation Regulation;
Final Regulation Certi?cation by the Governor

 

Final Omitted Regulation [3 Certi?cation by the Attorney General

 

 

 

 

Contents

Questron 7 5

.
Question 3 5

Question 9

5

Question 10 6
Compelling public interest and public bene?t General 6
State Review of Oil and Natural Gas Environmental Regulations 8
Separate Regulatory Chapters to Differentiate Between Conventional and Unconventional Requirements
Electronic F?mg 9
Threatened and Endangered Species 10
Addressing Potential Impacts to Public Resources 10
Protecting Waters ofthe Commonwealth 15
Antidegradation 15
Noti?cations . 16
Protection ofWater Supplies 17
Predrilling or Prealteration Survey 18
Area ofReVIew 19
Control and Disposal Planning (PPC Plans) 20
Temporary Storage 22
Control, Storage and Disposal ofProduction Fluids 25

Onsite process1ng29
Radiation Protection Action Plan 78.58(d) and 78a.58 30
ImpoundmentsBO
Onsite Disposa133
Containment 34
Site Restoration36
Spill Response 39
Borrow P1ts40
P1pe11nes41
Water Management Plans 44
Road Spreading oanne 45
Production 45



.

Question 11 . . . 46

Question 12 46
Protection ofWater Supplies 47
Predrilling or prealteration survey 49
Area ofReVlew 51
Control and disposal planning
Containment 54
Tanks used for temporary stelage 56
Tanks used for produced ?uids 58

53

2

 

 

 

 

Pits for temporary storage 59
Onsite disposal of drill cuttings and residual waste 62
OnsiteProcessing 
impoundments 64
Site Restoration 65
Spill Reporting and Remediation 69

. .
Plpelmes 72

Water Management Plans 73

- .15

Brine Road Spreading?Deicing, .. 

.. 



Question 13

77

.
Question 14 

.
Questlon 15 79

81

16
Questlon 

Question 17 82



Question 18

Question 19 84
Unconventional Operators Costs (Chapter 78a) 84
ConVentional Operators Costs 104
Unconventional Operators Sav1ug3124
Conventional Operators Savmgs 125
Companies Savings 12'?

Question 20127

128

Question 21

129

22
Questlon 

Question 23 13?.

134

.

Question 24

.
Question 25 141

Questlon 26 143

3

 

 

 

 

De?nition ofOiI and Gas Operations 144
Setbacks and consideration ofpubh'c resources 144
Noise Mitigation Requirements 145
Protection ofWater Supplies 146
Predr?ling or lore?alteration survey 146
Pits for Temporaiy 147
Noti?cation Requirements for Temporary Storage 147
Unauthorized Access by Third Parties 147
148
Ban the use ofand force removal ofal] buried tanks. 148
Periodic inspection ofproduction tanks 149
Tank 149
Centralized 149
Ban the discharge oftophoie water for a number ofreasons 150
Disposal ofresidual waste 150
Seasonal high water table 151
Borrow pits 151

 

Prpehnes 151
Water Management Plans 155
Road?spreading ofbrine for dust oontroi and road stabihzation 156 

E?rewvetting, anti~icing and ?Sewing 156

156

.
Question 27

162

Questlon 28

186

.
Ques??on 29

Question 30 186

Appendix A4 Table Summarizing Costs and Savings From FinainForm Rulemaking 187

 

 

 

Therefore, the Department is not assigning additional costs based on the requirements of this ?nal?form
rulemaking.

New noti?cations to the Department

The final rule includes a number of new noti?cation requirements. Operators must provide at least 3 days?
notice to the Department prior to conducting the following activities.

0 installation of pit liner (7 8.56)

I prior to commencing construction of a pit of greater than 250 ft2 for servicing, plugging or
recompleting a conventional well (78.5 

- prior to disposal of cuttings (78.61-78.63)

- prior to conducting onsite processing (78.58)

I prior to utilizing modular aboveground storage structure (78.56)

I after noticing deficiencies in tanks during or quarterly inspections (78.5 

The total new cost of this provision is 

Identi?cation of Public Resources 
The requirements in this section ensure that the Department meets its constitutional and statutory obligations

to protect public resources. I

The Department received signi?cant public comment on these provisions ?om unconventional gas well
operators related to the cost of implementing the public resource screening process requirements in Section
Commenters disagreed with the Department?s estimates of cost for permit conditions mitigation
measure to protect public resources. Commenters also argued that there will be considerable expenses related
to personnel time, expert consultants needed for surveys and project delays in associated with the responses
from public resource agencies. The Department acknowledges that there is some cost associated with
implementing these requirements. The total cost of this provision will vary on a case-by-case basis. This cost
is dependent on several variables including, the number of well sites that are within the prescribed distances
or areas listed, the type and scope of operations within prescribed distances or areas, the type of public
resource, the functions and uses of the public resource, speci?c probable harmful impacts encountered and
several other variables and the available mitigation measure to avoid, mitigate or otherwise minimize
impacts. Because so many signi?cant variables exist, the cost estimate for implementation of the entire
provision will vary. For that reason, the Department provides below an estimate for specific steps which
allow for an estimate to be made.

The ?rst step in the process is identi?cation. The Department believes this process would be required for all
new well sites. First an electronic review can be conducted with the Conservation Explorer?s
online planning tool. This tool will allow operators to identify the location of the majority of public resources
which require consideration under the fmal rule. This tool also will allow the operator to identify potential
impacts to threatened and endangered species, which also must be addressed under Since the
tool may not have data to identify all the public resources listed in Section operators will also
need to conduct a ?eld survey of the proposed well site area to identify public resources. This field survey
will likely include identi?cation of schools and playgrounds 200 feet from the limit of disturbance of the well
site. The Department estimates the cost of this ?eld survey to be $2,000 and the cost of the electronic survey

86

 

to be $40. Even though use of the online tool is currently required to comply with requirements protecting
threatened and endangered species, the Department has included the cost in this estimate nonetheless.

$2,000 434 $868,000
$40 434 $17,360

$868,000 $17,360 $885,360

The second step of the process is consultation with the public resource agency. This process is only
applicable to well sites which are Within the prescribed distances or areas listed in Section 7 8. 5 03(1). The
Department estimates that 30% of well sites will fall within these distances or areas. Operators will be
required evaluate the functions and uses of the public resource, determine any probable harmful impacts to
the public resource and develop any needed mitigation measures to avoid probable harmful impact. Operators
must also notify potentially impacted pubic resource agencies of the impact and provide those public
resource agencies the same information provided to the Department. Cost of the provision is dependent on
the number of well sites impacted as well as the complexity of evaluating the functions and uses of the public
resource. The Department estimates the postage will cost $20 per notification to public resource agencies.

$20 434 30% 2 $2,604

Due to the complexity of the variables in this process, the estimate for the cost of evaluating the functions
and uses of the public resource and determining whether there is a. probable harm?il impact will vary. In
some cases, functions and uses of the public resource and any probable harmful impacts may be immediately
obvious and others may be far more complex and may include multiple public resources.

The ?nal step in the process is mitigation. The cost estimate for mitigation will vary. In some circumstances,
an operator may be able to plan the location of the well site using the planning tool discussed above to avoid
public resources resulting in zero cost. Any cost associated with mitigation measures is dependent on many
variables and may be situation speci?c in some cases. While the Department is unable to provide a speci?c
estimate for the implementation of this entire provision, it should be noted that this cost may be substantial
depending on the location of the well site.

$885,360 $2,604 $887,964

he total cost of this provision is 8 $887,964 (not including consultation and mitigation).

Protection of water supplies 8a.51)

This section provides the Department?s interpretation of the water supply restoration and replacement in
Section 3218(a) of the 2012 Oil and Gas Act. This section seeks only to provide clarity to existing statutory
requirements. Accordingly, the estimated new cost incurred by unconventional operators is 

The total new cost of this provision is 80.

Area of Review and Monitoring Plans (?7Sa.52a and ?78a.73)

87

 

$8,720
$8,720 1,300 wells $11,336,000
he total cost ofthis provision is $11,336, 000.

The Department's 2013 Regulatory Analysis estimated the compliance cost at $2,000 per new well. That
Department estimate was made before the revisions to the fmal?form rulemaking, including;

a. Researching the depth of identi?ed wells;

b. Development of monitoring methods for identi?ed wells, including visual monitoring under
accompanying section 78.73;

c. Gathering surface evidence concerning the condition of identi?ed wells;

d. Gathering GPS, coordinate data for identi?ed wells;

e. Introduction of a provision of advanced notice to adjacent operators under accompanying section
78.73; and 

f. The assembly of the above data in an area of review report and monitoring plan and the submission of
the report at least 30 days prior to the commencement of drilling the well at well sites where

hydraulic fracturing activities are anticipated.

With the additional items, the cost of compliance is expected to exceed $2,000 per well. However, it is
important to emphasize that industry commentators have indicated the majority of the work required as part
of the area of review is already performed by operators in an effort to not only reduce potential environmental
liability, but also to protect the investment associated with the drilling and stimulation of a new well, which
represents millions of dollars for a typical unconventional well.

Further, it should be emphasized that the costs associated with the review of historical data will be negligible,
as most unconventional companies already have subscriptions to well?location databases. EDWIN, which is
one of the primary databases used for retrieving records related to oil and gas wells in costs
$500 per year for a full subscription. For a company drilling 25 wells a year this results in a cost of $20 per
well along with search and retrieval costs. Many other sources of information are free.

Most unconventional companies hire professional engineering ?rms to complete surveying activities.
Estimates for the generation of plats, which are already required for well drilling permits, are expected to
range between $4,000 and $5,000, with an average cost of $4,600. These costs were gathered by speaking
with companies that routinely perform this work for the unconventional industry. Assumptions include two
(2) days of ?eld work and one (1) day of of?ce work to compile the data necessary for submission. It should
be noted that current laws in only require that survey data be collected by a ?responsible
surveyor or engineer,? and that existing law. under Section 3213(a.1) of Act 13 and the prior 1984 Oil and
Gas Act has required operators to identify all abandoned assets discovered on their leases to the Department
for many years. It is noted that one company providing information did ask that the Department consider the
additional burdens being placed on the industry and expressed concerns that more oil and gas activities
would be shifting to neighboring states as a result of this regulation. The individual had asked that limits be
placed on offset wells requiring identi?cation in the area of review (active only) and had indicated that
landowners in drilling units have reacted in a confrontational manner with members of his staff in the past.

88

 

The Department has experience monitoring well vents in its plugging program. Costs are anticipated to
remain under $500 per day per offset well; although the number of wells requiring continuous monitoring is
not expected to be ve1y high on a case-by-case basis, as monitoring candidates must not only penetrate the
zone expected to be in?uenced by hydraulic fracturing, but also represent a high enough risk that continuous
monitoring is deemed warranted. In many cases avoidance mitigation measures, plumbing a tank to the well
of concern or inspecting offset well sites periodically may be all that is necessary. For at least a fraction of
the well drilled, no offset wells will penetrate the zone of concern and monitoring costs will be negligible.
This cost item is expected to range from negligible amounts to a maximum of $7,500 per well site, with an
average cost of $3,500.

There are nominal costs associated with a certi?ed mailing program that assumed 100 landowners are
contacted in association with a well site at a cost of $6.00 per mailing.

Although the Department contends that the work speci?ed in this section of the regulation is already being
conducted by responsible unconventional operators in the state and implementation will merely result in a
marginal incremental cost for reporting, its cost analysis based on speaking with quali?ed professionals and
its own experience contracting services in its well plugging program projects that total costs for an
unconventional well operator employing standard industry practices could conceivably average around
$9,000 per well site.

For comparison, the Department recently analyzed costs associated with several unconventional well
hydraulic fracturing communication incidents documented in The circumstances surrounding
these incidents varied: three involved communications between a well being stimulated and a nearby well
being drilled, another involved communication between two stimulated wells that had not been ?owed back
and a wellbeing hydraulically fractured on the same pad, and the last involved communication with a
previously unknown and inadequately plugged conventional well. Costs associated with unconventional
wells tend to be derived from a more complicated set of variables that not only must factor in the equipment
being used and subsequently placed on standby at the time of the incident costs range from $10,000 to
$50,000 per day); but also lost revenues in association with delayed production and the need to meet gas-
market commitments by established deadlines that may prompt reconfiguring existing well network flow~to~
pipeline parameters and/or purchasing gas on the open market. These costs are potentially further
compounded by any environmental issues that must be addressed water well sampling/monitoring and
analytical costs and consultant costs for data analysis and interpretation), logging and downhole camera costs
to inform any well work that must be completed, plugging costs of any unconventional wells affected beyond
repair and any improperly plugged legacy wells, material costs loss of drilling muds that are normally
rented), increased monitoring costs at nearby gas wells, increased time spent bleeding pressure down in the
reservoir, and accelerated expenditures to prepare a new site. Cost estimates for the first three incidents
ranged from $90,000 to $800,000. Total costs for the second scenario, which involved plugging two drilled
unconventional wells that had not been brought back into production, are estimated at $13,000,000 to
$16,000,000. Total costs for the third scenario were in excess of $1,000,000. The Department acknowledges
that in certain cases, even with the implementation of the regulation and the application of best practices, that
some percentage of communication incidents will still take place. However, it adds that this regulatory
concept is being addressed and acknowledged by a number of other regulatory programs, the STRONGER
organization and API, a globally recognized industry trade organization. It is also signi?cant to note that a
single, severe hydraulic fracturing communication incident is capable of exceeding the estimated annual cost
of implementation for an entire unconventional industry.

89

 

 

Some operators may only need a single plan and others may need several, depending on their operations.

The Department estimates that development of a radiation protection action plan under this section will cost
between $2,000 and $5,000 per plan for initial development. In addition, in order to implement the plan,
operators who develop a plan will need to purchase a dose rate meter. The Department estimates the cost of
the dose rate meter to be Finally, operators will be required to provide training on the plan to
staff. This training is typically conducted by the plan development consultant but may be conducted by
others. The Department estimates that annual training of staff will cost $1,000- $2,000 per plan.

Cost of Development
163 $2,000 $326,000
163 $5,000 $815,000

Cost of Training 
163 $1,000 $163,000
163 $2,000 $326,000

A new meter will not be required for each plan. Operators may be able to use the same meter for multiple
sites throughout the year depending on the location of the site. The Department estimate that industry will
need to purchase 85 dose rate meters to comply with this requirement.

Cost of meters
85 $1,000 $85,000
85 $2,000 $170,000

The total annual cost is equal to the cost of development plus the cost of training. The total initial cost is
equal to the cost of meters.

$326,000 $163,000 $489,000
$815,000 $326,000 $1,141,000

Therefore, the estimated annual cost of this provision is between $489, 000 and $1,141, 000 and the estimated
initial cost is estimated to be beaveen $85, 000 and $1 70, 000.

Well Development Impoundment Construction Standards (78a.59a, 78a.59b)

In the ?nal rule, 78a.59a and 78a.59b impose construction and operation standards for well development
impoundments including embankment construction standards, the need for surrounding well development
impoundments with a fence and providing an impermeable plastic liner. The department received comments
from unconventional operators indicating that the cost of all new requirements applicable to well
development impoundrnents, excluding fencing around the impoundment, is $250,000 to $500,000 per
impoundrnent and a total cost of $25,000,000 based on the Department?s estimate of 100 existing ?'eshwater
impoundments. The commenter does not provide a breakdown of how the projected cost was derived.

The Department disagrees with the commenter?s cost estimate. First, many of the new requirements are only
applicable to new impoundments. Operators must only certify that existing impoundments meet the

95

 

requirement for having a liner, being surrounded by a fence and properly storing mine in?uenced
water. The rule does not require any certi?cation of structural integrity or a groundwater depth determination
for existing impoundments so those costs should not be considered for existing impoundments. The
requirement to ensure that mine in?uenced water is properly stored exists regardless of the well development
requirements in Chapter 78 so those costs should not be considered for existing impoundments.

The Department understands that the majority of existing well development impoundments already have an
impermeable liner. in addition, it is important to note that the well development impoundment
requirements do not apply to water sources such as lakes or ponds, so to the extent that commenters included
these types of facilities in their cost estimate, they may have overestimated. The Department estimates that
90% of the existing well development impoundments have a liner installed so only a small number
of well development impoundments will require addition of a liner under the rule. The Department
made the initial estimate of 100 existing well development impoundments in 2013 which would equate to an
ayerage of 20 well development impoundments constructed per year. Based on this rate of development, the
number of existing well development impoundments is estimated to be 140 since 2 years have passed since
the initial estimation.

The Department estimates that on average, a well development impoundment will require 250,000 ft2 of
liner to comply with the rule. The estimated cost of installed 30 mil HDPE liner to meet this
requirement is $0.40/ft2 resulting in a total cost of $1,260,000.

250,000 0.40 90% 140 $1,260,000 for liner installation

The cost of the fencing is dependent upon the size of the impoundment and the type of fencing used
determines. Based on 140 well development impoundments throughout the Commonwealth and assuming
that none of them currently have fencing the Department estimates that the total cost of this provision is
between $980,000 and $7,000,000.

$7,000 140 $980,000
$50,000 140 $7,000,000

The rule also requires operators to register the location of well development impoundments with the
Department. Assuming a total of 140 existing well development impoundments, the Department estimates a
total cost of $13,000.

$1,260,000 $980,000 $13,000 $2,253, 000
$1,260,000 $7,000,000 $13,000 $8,273, 000
The initial cost ofthis provision is estimated to be 'benveen $2,253, 000 and 8,273, 000.

For new impoundments, the total co st is dependent upon the number of new impoundments constructed.
Based on past trends, the Department estimates that 20 new well development impoundments will be
constructed each year. The standards under 78a.59b provide reasonable requirements to ensure that well
development impoundments are structurally sound and protective of public health and safety and the
environment. The standard of structurally sound and protective of public health and safety and the

96

 

environment is a standard that all well development impoundments should meet. To the extent that operators
are currently engaged in the practice of constructing and operating impoundments that are not structurally
sound and protective of public health and safety and the environment, the Department asserts that they are
not only operating irresponsibly but also out of compliance with Department regulations. The Department
also notes that 78a.59a(b) allows an manner or operator to deviate from the requirements in this section
provided that the alternate practices provides equivalent or superior protection to the requirements in 

78.5 9a and 78a.59a. Therefore, these sections should not create any signi?cant new costs to responsible
operators. -

The Department estimates the cost of determining the depth of the seasonal high groundwater table to be
$3,500 per impoundment.

The Department estimates a total cost of $100,000 for installing liners in each impoundment based on the
cost of $0.40/ft2 for installed 30 mil HDPE liner and 250,000 ft2 of liner per impoundment on average.

The Department estimates the cost of installing fencing to be $7,000 - $50,000 per impoundment depending
on the size of the impoundment and the type of fencing used.

This results in a total estimated cost of $110,500 and $153,500 per impoundment and a total annual cost of
$2,210,000 and $3,070,000.

($3,500 $100,000 $7,000) It 20 $2,210, 000
($3,500 $100,000 $50,000) it 20 070, 000
Therefore, the total estimated annual cost of this provision is between $2,210, 000 and 33, 070,000.

Centralized Impoundment 78a.59c)

The ?nal rule requires unconventional operators to either close or obtain a permit from the Department?s
waste management program for existing centralized impoundments. The Department did not include a cost
estimate for this provision when the rule was initially proposed because it allowed for continued use of these
facilities under Chapters 78 and 78a. The cost of this provision is dependent on the number of facilities
impacted and how operators decide to comply. The Department received signi?cant comment on this section
from unconventional operators. Commanters estimate that the cost to permit a new centralized impoundment
under Chapter 289 may increase by $120,000 to $230,000 based on site conditions. Commenters also noted
that if an operator chooses to close an existing permitted centralized impoundment due to this rule, an owner
may realize a loss of $1,500,000 to $2,500,000 of investment plus the immediate additional costs to restore
the site. If a centralized impoundment permit has been submitted to the Department under the current
regulations and is pending review, an applicant would realize a loss of $150,000 to $250,000 plus costs
associated with the time to prepare the application as a result of this revision.

The Department does not agree with these cost estimates. First, the costs associated with restoration of
existing centralized impoundments should not be considered because restoration of the centralized
impoundment has always been required. Second, the standard for construction of a centralized impoundment
under Chapter 78 and the Department?s existing centralized impoundment program are substantially similar
to those required by the residual waste regulations. The Department believes that the majority of costs

97

 

associated with development of pending applications under the existing centralized impoundment program
are applicable to the costs associated with the residual waste permit and therefore no cost should be

associated with pending applications.

The cost associated with this provision is dependent on the number of impoundments impacted. There are a
total of 26 centralized impoundments operated by 6 unconventional operators in the Commonwealth. The
Department believes that operators will choose to restore a number of the existing impoundments rather than
obtain a permit from the Department?s waste management program because older centralized impoundments
were not constructed to standards as closely matched to the waste requirements as newer impoundments and
those older impoundments also may be approaching the end of their useful lives. The Department presumes
that the replacement cost for each centralized impoundment is between $1,500,000 and $2,500,000. To the
extent that operators choose to restore and replace all of the existing centralized impoundments, the
estimated cost of this provision is between $33,000,000 and $55,000,000.

20 $1,500,000 $30, 000, 000
20 $2,500,000 350, 000,000
The initial cost of this provision is estimated to be between $39, 000, 000 and $65, 000,000.

Based on past trends, the Department estimates that 4 centralized impoundments will be constructed per year.
Ifthe cost to permit and construct impoundments under the Chapter 289 is $120,000 to $230,000 per
impoundment, the estimated annual cost is between $480,000 and $920,000.

Therefore, the total estimated annual cost of this provision is estimated to be between $480, 000 and
$920, 000.

Onsite Disposal 

The ?nal rule requires unconventional operators to obtain a permit from the Department prior to disposing
contaminated drill cuttings or drill cuttings from below the surface casing seat either in a pit or by land
application on the well site. This revision removes the permit by rule structure for waste disposal on
unconventional well sites. The Department does not expect this provision to add any signi?cant cost for
unconventional operations. It has become less and less common for unconventional operators to utilize onsite
disposal of contaminated drill cuttings and drill cuttings from below the surface casing seat. In fact, there
have been many instances, where unconventional operators have exhumed previously encapsulated cuttings
due to liability concerns. In addition, the practice of drilling many wells on a single site is generally
incompatible with onsite disposal simply due to the volume of waste materials generated and the limited
space available. An example of this is the Big Sky pad in Green County where a total of 22 wells have been
drilled as of May 2015.

The total cost of this provision will be dependent on the number of well sites where operators seek permits
for onsite disposal. The Department?s review of waste disposal data for unconventional wells shows that for
the reporting periods from January?June of 2014, July?December 2014 and January-June 2015 cuttings from
only 5 wells have been disposed through onsite encapsulation and no cuttings have been disposed through
land application. During that same time period, 1,746 unconventional wells were drilled so less than 0.3% of
wells utilized onsite disposal. In addition, the 5 wells which utilized onsite disposal were vertical wells that 

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When initially proposed, this provision required that the materials used for secondary containment
must demonstrate compatibility with the contained ?uid. Commentators pointed out that ASTM D5747 is a
test for land?ll liners and pits where the liner is submerged in diluted chemicals for extended period of time
and the test costs around $5000 to run on each chemical type found at a site. Operators suggest ASTM D543
as an alternate test. By considering the comments, rulemaking language has been changed and the
Department allows for the use of test methods if approved by the Department.

Since this is an existing statutory requirement that unconventional operators must already comply with, the
total new cost of this provision is 

he total new cost of this provision is 
Site Restoration (?7Ba.65)

This section largely restates the restoration requirements in Section 3216 of the 2012 Oil and Gas Act and
incorporates the Department?s interpretation of these requirements and the existing Chapter 102 requirements
as outlined in the ?Policy for Erosion and Sediment Control and Stormwater Management for Earth
Disturbance Associated with Oil and Gas Exploration, Production, Processing, or Treatment Operations or
Transmission Facilities?, Document No. 800-2100-008, which was ?nalized on December 29, 2012. The
revisions to section 78a.65 in the ANF were also intended to address comments on this section that
indicated continuing confusion regarding what constitutes restoration as the term is used both in Chapter 788.
as well as in Chapter 102, and what the associated requirements are. The changes to this section in the ANFR
clarify this question and in particular distinguish between areas not restored and other areas. ?Areas not
restored? do not fall within the provisions in section 102.8(n) and therefore must meet the requirements, inter
alia, of section Areas not restored include areas where there are permanent structures or impervious
surfaces.

The Department received signi?cant comment on this provision from unconventional operators. Commenters
argued that the Department failed to include any estimate for the cost associated with the new site restoration
requirements. Commenters did not agree with the Department?s position regarding cost savings due to the
added provision of two-year extension of the restoration period. Unconventional operators estimated that the
cost of well site restoration will be approximately $200,000 to $300,000 per pad; not $50,000 as Department
estimated. Therefore, rather than a $21,700,000 savings, the restoration requirements are a cost of
$130,000,000.

The Department does not agree with these cost estimates. The restoration requirements in this section are not
new and do not impose a new cost on the regulated community as explained above. In addition, the
Department disagrees with commenters? assertions that the extension requirement is merely a postponement
of the cost. This section mirrors the requirements in Section 3216(g) of the 2012 Oil and Gas Act that allow
operators to request to extend the restoration period for up to two years so that an operator does not have to
restore the site and then disturb it again if it plans to drill additional wells on the same well pad. The cost
savings associated with the restoration extension are derived from avoiding the cost of restoring the site
within 9 months of completion of drilling and later having to reconstruct the site and restore it again. The
Department has revised its estimate that this provision will result in $21,700,000 in cost savings. Since the 2-
year extension is provided by statute, operators may be granted an extension regardless of the status of

78a.65, the revisions to this section do not represent a cost savings for operators.

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This section is intended to provide clarity for implementing existing requirements from both Act 13 and
Chapter 102. To the extent that an operator would incur the costs listed above, they would incur those costs
regardless of the status of 78a.65 because they are costs associated with complying with Act 13 and

Chapter 102.
The total new cost of this provision is 
Re ortin and remediation of ills and releases 78a.66

Section 78a.66 establishes a reporting and remediation process for spills and releases that occur on well sites
and access roads including a requirement to follow the procedures established under Act 2. Prior to this rule,
the Department addressed spills through the policy ?Addressing Spills and Releases at Oil Gas Well Sites
or Access Roa which included allowances for use of an alternative process. The ?nal rule eliminates use
of the alternative process. The Department received signi?cant public comment on this section from oil and
gas operators indicating that the Act 2 process increases the cost of remediation by 3?4 times the alternative
process. Commenters also noted an individual cost in which they asserted that the remediation should have
only cost $10,000 but was expected to cost $250,000 due to the Act 2 process. Commenters did not provide
any speci?c details to fully explain the estimated costs. Commenter?s also argued that the timelines
established for completing various steps of a spill remediation are inappropriate and overly burdensome for

the oil and gas industry.

The Department does not agree with the cost estimates. The cleanup process established under 78a.66
include the steps necessary to ensure that spills are appropriately remediated. To the extent that operators are
remediating spills, they should generally be conducting the steps outlined by the Act 2 process. To the extent
that operators are not conducting the steps outlined by the Act 2 process, the Department asserts that they
may not be properly remediating spills. Therefore, since operators should already be conducting the required
steps, the only new requirement under this rule is that operators must follow the Act 2 process in accordance
with the required timelines. Since operators are required to remediate spills, the Department does not believe
that the timelines established under this section represent a new cost, as commenters have noted,
postponement of a cost is not an avoidance of the cost. The Department does not believe that a requirement
to follow the Act 2 process represent any signi?cant burden on the oil and gas industry.

The total cost of this provision is dependent upon the total number of spills or releases that must be reported
and remediated. It is not possible for the Department to predict the number of spills or releases that will occur
at well sites. Therefore, the Department is unable to provide a speci?c cost estimate for this provision;
however, the Department does not believe that this provision represents any signi?cant new cost to the oil

and gas industry.
Borrow Pits (S 78a.67)

Subsection 78a.67(b) require the registration of the location of existing borrow pits within 60 calendar days
after the effective date of the ?nal?form rulemaking and registration of new borrow pits before there are built.
This will be done electronically through the Department?s website. There were a few comments from
operators that this would be burdensome on industry. The Department does not believe that the requirement
to register the location of existing borrow pits with the Department represents a signi?cant burden on the
industry and has not assigned a cost to this requirement.

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directional bores completed and the terrain in which the bores are completed. The Department does not have
suf?cient data to produce an estimated cost of these provisions but since most operators should already be in
compliance with the bulk of these common sense environmental controls, the Department does not believe
that this section will result in any signi?cant burden to the oil and gas industry.

Well DevelopmenLPipelines for Oil and Gas operations (8 783.6%)

Subsections and establish common sense environmental controls for constructing and operating
well development pipelines. These requirements are intended to help ensure that operators maintain
compliance with the Clean Streams Law, Chapter 102 and Chapter 105 when constructing and operating well
development pipelines. The Department believes that most operators aheady comply with the bulk of these
requirements and will not have to make any signi?cant changes to their operations. The cost of these
provisions is dependent on the number of well development pipelines constructed and utilized and the terrain
in which the well development pipelines are constructed. The Department does not have suf?cient data to
produce an estimated cost of these provisions but since most operators should already be in compliance with
the bulk of these common sense environmental controls, the Department does not believe that this section
will result in any signi?cant burden to the oil and gas industry.

Prohibition of buried well development pipeline (8 

One speci?c requirement in this section is the requirement that well development pipelines that carry ?uid
other than fresh ground water, surface water, water from water purveyors or water from Department
approved sources must be installed aboveground except when crossing pathways, roadways, railways, water
courses or water bodies. The rule also limits the use well development pipelines to a time period of 1 year.
Operators expressed signi?cant concems about these provisions because many operators maintain a network
of buried pipelines that ?t the de?nition of well development pipelines. Commenters did not provide any cost
estimates to the Department for this provision.

The cost of these provisions is dependent on the number of pipelines that are impacted. The Department does
not have suf?cient data to make a detailed cost estimate but notes that the costs could be substantial.

Water management plans (5 783.62)

The ?nal rule implements requirements in 3211(m) which requires anyone who withdraws or uses water
from water sources within for drilling or hydraulic fracture stimulation of any natural gas well
completed in an unconventional gas formation to do so in accordance with an approved water management

plan.

Since this section implements existing statutory requirements, it does not represent a new cost to the oil and
gas industry.

he total new cost of this provision is 3 0.
Waste Reporting Requirements (5 7821.121)

The ?nal rule includes a requirement for unconventional operators to report waste production to the
Department on a basis. This new rule is different from the existing requirement to report once every

103

 

6 months. The Department received significant comment on this requirement from operators indicating that it
is costly and overly burdensome. Commenters estimated that waste reporting will take 20-30 hours on
average regardless of the length of the reporting period. The new cost associated with this provision is the
difference in the current cost to report and the new cost to report. The Department assumes a labor rate of
$30/hour to do the reporting.

The current cost is between $1,200 and $1,800 per year for each operator

20 hours $30/hour 2 reports/year $1,200
30 hours $30/hcur 2 reports/year $1,800

The new cost is between $7,200 and $10,800 per year for each operator.

20 hours $3 O/hour 12 reports/year $7,200
30 hours $30/hour 12 reports/year $10,800

The total new cost is between $6,000 and $9,000 per year for each operator.

$7,200 - $1,200 $6,000
$10,300 - $1,300 $9,000

The total cost of this new requirement is equal to the average new cost per operator times the number of
operators.

73 operators $6,000 $43 8,000
73 operators $9,000 $657,000

Therefore, the total estimated annual cost of this provision is estimated to be between $438, 000 and
$65 7, 000.

The estimated annual cost of this regulation an unconventional operators is between $5,895,500 and
$31,149,664 with an initial cost of between $41,358, 000 and $73,463,000 incurred in the ?rst 3 years.

The Department has provided a summary table of estimated costs in Appendix A.

Conventional Operators Costs

Prior to initially proposing revisions to this rule, the Department reached out to oil and gas operators,
subcontractors, and industry groups to derive the cost estimates of the fmal?form rulemaking. The
Department received signi?cant comment regarding the cost estimates provided by the Department when the
rule was proposed. Commenters also included comprehensive analysis of their estimated costs of the
proposed rule. As a result of those comments and other information, the Department made signi?cant
revisions to the ?nal rule.

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Mus

CERTIFICATE OF SERVICE

 

I hereby certify that a true and correct copy of the foregoing Petition for

Review in the Nature of a Complaint seeking Declaratory and Injunctive Relief

was served by certi?ed mail on the 13th day of October, 2016 upon:

Attorney General Bruce R. Beemer
Of?ce of
Attorney General
Strawberry Square
16?h Floor
Harrisburg, PA 17120

Patrick McDonnell
Acting Secretary, Department of
Environmental Protection
Chairperson, Environmental
Quality Board
Rachel Carson State Of?ce Building
16th Floor
400 Market Street
Harrisburg, PA 17101

Alexandra C. Chiaruttini, Esquire

Chief Counsel, Department of
Environmental Protection

Rachel Carson State Of?ce Building

400 Market Street

Harrisburg, PA 17101

Kimberly Childe, Esquire

Counsel, Environmental
Quality Board

Director, Bureau of Regulatory
Counsel

P. O. Box 8464

9th Floor

400 Market Street
Harrisburg, PA 17105

   
  

M. Mosite 
ST, CALLAND, CLEMENTS
ZOMNIR, P.C.

Two Gateway Center

Sixth Floor

Pittsburgh, 15222
(412) 394-5400

Counsel for Petitioner,
The Marcellus Shale Coalition