# HILCORP ALASKA, LLC — Warning Letter

- **operation:** document
- **citation:** CPF 520192002W
- **title:** HILCORP ALASKA, LLC — Warning Letter
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2019-01-25
- **effective on:** Not available
- **summary:** CLOSED warning letter citing 191.15(a), 191.22(c), 191.5(a), 192.481(a), 192.605(a), 192.619, 192.739(a)(1), 192.743(a), 192.745(a).
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- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-520192002w.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-520192002w
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/520192002W
**body:**

Warning Letter involving HILCORP ALASKA, LLC. PHMSA's enforcement data identifies the cited regulations as 191.15(a),  191.22(c),  191.5(a),  192.481(a),  192.605(a),  192.619,  192.739(a)(1),  192.743(a),  192.745(a). The case was opened on 2019-01-25 and is reported as closed as of 2019-01-25. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520192002W_Closure Letter_06022025_(16-152926S).pdf: https://primis.phmsa.dot.gov/enforcement-documents/520192002W/520192002W_Closure%20Letter_06022025_(16-152926S).pdf

520192002W_Closure Letter_06022025_(16-152926S)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520192002W/520192002W_Closure%20Letter_06022025_(16-152926S)_text.pdf

520192002W_Consent Agreement and Order_05182020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520192002W/520192002W_Consent%20Agreement%20and%20Order_05182020.pdf

520192002W_Consent Agreement and Order_05182020_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520192002W/520192002W_Consent%20Agreement%20and%20Order_05182020_text.pdf

520192002W_Operator Response to Notice and Request for Hearing and Preliminary Statement of Issues_02222019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520192002W/520192002W_Operator%20Response%20to%20Notice%20and%20Request%20for%20Hearing%20and%20Preliminary%20Statement%20of%20Issues_02222019.pdf

520192002W_Warning Letter_01252019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520192002W/520192002W_Warning%20Letter_01252019.pdf

520192002W_Warning Letter_01252019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520192002W/520192002W_Warning%20Letter_01252019_text.pdf

520192002W_Warning Letter_01252019_text.pdf

WARNING LETTER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
January 25, 2019
Mr. Greg Lalicker
Chief Executive Officer
Hilcorp Alaska, LLC
1111 Travis Street
Houston, Texas 77002
CPF 5-2019-2002W
Dear Mr. Lalicker:
On July 11 through 15, 2016 and October 26, 2016, representatives of the Pipeline and
Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS),
pursuant to Chapter 601 of 49 United States Code (U.S.C.), inspected Hilcorp Alaska, LLC’s
(Hilcorp) Middle Ground Shoal natural gas transmission pipeline system near Nikiski, Alaska.
We also reviewed your operation, maintenance and emergency response procedures and
supporting records at your Nikiski and Anchorage offices.
Based on our inspection findings, PHMSA determined that Hilcorp committed probable
violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR).
The deficiencies noted and the probable violations are:
1. §191.5(a) Immediate notice of certain incidents.
(a) At the earliest practicable moment following discovery, each operator shall
give notice in accordance with paragraph (b) of this section of each incident as
defined in §191.3.



Records do not indicate immediate notifications of incidents were made in accordance with
§191.5. The previous operator failed to provide notice to the National Response Center of a
natural gas leak on August 31, 2014, as confirmed by the Hilcorp personnel interviewed.
2. § 191.15 Transmission systems; gathering systems; and liquefied natural gas
facilities: Incident report.
(a) Transmission or Gathering. Each operator of a transmission or a gathering
pipeline system must submit DOT Form PHMSA F 7100.2 as soon as practicable
but not more than 30 days after detection of an incident required to be reported
under §191.5 of this part.
Records do not indicate that transmission incident reports were submitted by the previous
operator to DOT on Form 7100.2 (01-2002) within the required timeframe. Incident reports
were not submitted for the June 1, 2014 and August 31, 2014 leaks on the transmission
pipeline system.
3. § 191.22 National Registry of Pipeline and LNG Operators (OPID)
(c) Changes. Each operator of a gas pipeline, gas pipeline facility, LNG plant or
LNG facility must notify PHMSA electronically through the National Registry of
Pipeline and LNG Operators at http://opsweb.phmsa.dot.gov of certain events.
Hilcorp failed to submit a National Registry notification to PHMSA regarding the September
1, 2015 purchase of the Middle Ground Shoal natural gas transmission pipeline system.
4. § 192.481 Atmospheric corrosion control: Monitoring
(a) Each operator must inspect each pipeline or portion of pipeline that is
exposed to the atmosphere for evidence of atmospheric corrosion, as follows:
If the pipeline is
located: Then the frequency of inspection is:
Onshore At least once every 3 calendar years, but with intervals not
exceeding 39 months
Offshore At least once each calendar year, but with intervals not exceeding 15
months
Hilcorp could not demonstrate that all portions of the pipeline that were exposed to the
atmosphere were inspected at the required time interval. Records provided to our inspectors
do not adequately document inspection of aboveground pipe for evidence of atmospheric
corrosion. Offshore atmospheric corrosion inspections for pipeline portions located on the
Platform A were not conducted in 2015.
2



5. § 192.605 Procedural manual for operations, maintenance, and emergencies.
(a) General. Each operator shall prepare and follow for each pipeline, a manual
of written procedures for conducting operations and maintenance activities and
for emergency response. For transmission lines, the manual must also include
procedures for handling abnormal operations. This manual must be reviewed
and updated by the operator at intervals not exceeding 15 months, but at least
once each calendar year. This manual must be prepared before operations of a
pipeline system commence. Appropriate parts of the manual must be kept at
locations where operations and maintenance activities are conducted.
The operators failed to conduct a review of its emergency plans and procedures at intervals
not exceeding 15 months, but at least once each calendar year. The Emergency Plans and
Procedures were reviewed on December 3, 2013 and again on November 24, 2015. The
interval between reviews was longer than 15 months, and no review was completed during the
2014 calendar year.
The previous operator also failed to document that annual reviews of the written procedures in
the operations and maintenance manual were conducted as required. Hilcorp was unable to
demonstrate that an annual review of operations and maintenance plans and procedures had
been conducted in the 2014 calendar year.
6. § 192.619 Maximum allowable operating pressure: Steel or plastic pipelines.
(a) No person may operate a segment of steel or plastic pipeline at a pressure
that exceeds a maximum allowable operating pressure determined under
paragraph (c) or (d) of this section, or the lowest of the following:
(1) The design pressure of the weakest element in the segment, determined in
accordance with subparts C and D of this part. However, for steel pipe in
pipelines being converted under §192.14 or uprated under subpart K of this part,
if any variable necessary to determine the design pressure under the design
formula (§192.105) is unknown, one of the following pressures is to be used as
design pressure:
(i) Eighty percent of the first test pressure that produces yield under section N5
of Appendix N of ASME B31.8 (incorporated by reference, see §192.7), reduced
by the appropriate factor in paragraph (a)(2)(ii) of this section; or
(ii) If the pipe is 123∕4 inches (324 mm) or less in outside diameter and is not
tested to yield under this paragraph, 200 p.s.i. (1379 kPa).
3



(2) The pressure obtained by dividing the pressure to which the segment was
tested after construction as follows:
(i) For plastic pipe in all locations, the test pressure is divided by a factor of 1.5.
(ii) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more, the test pressure
is divided by a factor determined in accordance with the following table:
Factors1, segment—
Class
location
Installed before (Nov.
12, 1970)
Installed after (Nov. 11,
1970)
Converted under
§192.14
1 1.1 1.1 1.25
2 1.25 1.25 1.25
3 1.4 1.5 1.5
4 1.4 1.5 1.5
1 For offshore segments installed, uprated or converted after July 31, 1977, that are not located on
An offshore platform, the factor is 1.25. For segments installed, uprated or converted after July
31, 1977, that are located on an offshore platform or on a platform in inland navigable waters,
including a pipe riser, the factor is 1.5.
(3) The highest actual operating pressure to which the segment was subjected
during the 5 years preceding the applicable date in the second column. This
pressure restriction applies unless the segment was tested according to the
requirements in paragraph (a)(2) of this section after the applicable date in the
third column or the segment was uprated according to the requirements in
subpart K of this part:
Pipeline segment Pressure date —Onshore gathering line that
first became subject to this
part (other than §192.612)
after April 13, 2006
March 15, 2006, or date
line becomes subject to this
part, whichever is later
Test date
5 years preceding
applicable date in
second column.
—Onshore transmission line
that was a gathering line not
subject to this part before
March 15, 2006
Offshore gathering lines July 1, 1976 All other pipelines July 1, 1970 July 1, 1971.
July 1, 1965.
4



(4) The pressure determined by the operator to be the maximum safe pressure
after considering the history of the segment, particularly known corrosion and
the actual operating pressure.
(b) No person may operate a segment to which paragraph (a)(4) of this section is
applicable, unless over-pressure protective devices are installed on the segment in
a manner that will prevent the maximum allowable operating pressure from
being exceeded, in accordance with §192.195.
(c) The requirements on pressure restrictions in this section do not apply in the
following instance. An operator may operate a segment of pipeline found to be in
satisfactory condition, considering its operating and maintenance history, at the
highest actual operating pressure to which the segment was subjected during the
5 years preceding the applicable date in the second column of the table in
paragraph (a)(3) of this section. An operator must still comply with §192.611.
(d) The operator of a pipeline segment of steel pipeline meeting the conditions
prescribed in §192.620(b) may elect to operate the segment at a maximum
allowable operating pressure determined under §192.620(a).
Hilcorp did not properly determine the maximum allowable operating pressure (MAOP) per
§192.619 and §192.620 for the transmission pipelines between Platform A to Platform C, and
Platform C to the Dillon Platform. The maximum allowable operating pressure for these
pipelines must be determined by §192.619(a), §192.619(c), or §192.619(d) requirements.
Hilcorp’s MAOP determination does not attempt to address §192.619(c) requirements.
Hilcorp has not identified these pipelines as alternative MAOP pipelines and, therefore, the
192.619(d) requirements are not applicable. Because Hilcorp did not perform the necessary
analysis required to proceed under §192.619(c) or § 192.619(d), §192.619(a) requirements
govern. In order to meet §192.619(a) requirements, Hilcorp must select the lowest of four
values determined by §§192.619(a)(1) – (a)(4). Hilcorp states that due to the lack of
information, including pressure test documentation, the MAOP of these lines was determined
by the requirements of §192.619(a)(4). This is inadequate, for without determining the
appropriate values for §§192.619(a)(1) - (a)(3), it cannot be determined if the §192.619(a)(4)
value is the lowest of the four values.
7. § 192.739 Pressure limiting and regulating stations: Inspection and testing
(a) Each pressure limiting station, relief device (except rupture discs), and
pressure regulating station and its equipment must be subjected at intervals not
exceeding 15 months, but at least once each calendar year, to inspections and
tests to determine that it is—
(1) In good mechanical condition;
(2) Adequate from the standpoint of capacity and reliability of operation for the
service in which it is employed;
Our field inspection revealed that pressure regulating control lines were not supported in a
manner to prevent damage so that they maintain good mechanical condition. Control lines
5



associated with the pressure reduction equipment (PV-1210 and PV-1211) within the
Distribution Building were not adequately supported and therefore unsafe.
Records do not indicate inspection and testing of a pressure relief device as required and at
the specified intervals. The operators failed to inspect and test PSV-2007 at intervals not
exceeding 15 months, but at least once each calendar year to determine its mechanical
condition, capacity, and reliability of operation for the service in which it is employed.
PSV-2007 was tested on September 4, 2014, placed into service on August 24, 2015, and
remained in service until July 6, 2016. PSV-2007 was in-service in calendar year of 2015
without being inspected or tested. In addition, PSV-2007 remained in service until July 6,
2016, which exceeded the 15 month interval.. Therefore, the PSV-2007 was in-service while
exceeding the inspection and testing interval required by code.
8. § 192.745 Valve maintenance: Transmission lines.
(a) Each transmission line valve that might be required during any emergency
must be inspected and partially operated at intervals not exceeding 15 months,
but at least once each calendar year.
During the inspection, Hilcorp identified two safety valves on Platform A (SDV-1810A and
SDV-2700), and three safety valves on Platform C (FDD-1610, SDV-1600, and SDV-1610)
that would be required during an emergency. The prior operator of these platforms, XTO,
previously identified only one safety valve each on Platform A and Platform C.
Hilcorp was unable to provide a record of inspection and partial operation of the
transmission line valves which were located on Platform A and Platform C during the
calendar years: 2013, 2014, and 2015.
9. § 192.743(a) Pressure limiting and regulating stations: Capacity of relief devices.
(a) Pressure relief devices at pressure limiting stations and pressure regulating
stations must have sufficient capacity to protect the facilities to which they are
connected. Except as provided in §192.739(b), the capacity must be consistent
with the pressure limits of §192.201(a). This capacity must be determined at
intervals not exceeding 15 months, but at least once each calendar year, by
testing the devices in place or by review and calculations.
Records indicate testing or review of the capacity of each pressure relief device at each
pressure limiting station and pressure regulating station was not completed as required.
Hilcorp provided pressure relief capacity calculations/reviews dated September 10, 2010 and
December 14, 2015. The September 2010 calculations/reviews were done when XTO was the
operator, and the December 2015 calculations/reviews were done by Hilcorp. No other
calculations/reviews were provided. Pressure relief capacity reviews were not conducted in
the following calendar years: 2011, 2012, 2013, and 2014.
6



Under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed
$209,002 per violation per day the violation persists, up to a maximum of $2,090,022 for a
related series of violations. For violations occurring prior to November 2, 2015, the maximum
penalty may not exceed $200,000 per violation per day, with a maximum penalty not to exceed
$2,000,000 for a related series of violations. We have reviewed the circumstances and
supporting documents involved in this case, and have decided not to conduct additional
enforcement action or penalty assessment proceedings at this time. We advise you to correct
the item(s) identified in this letter. Failure to do so will result in Hilcorp being subject to
additional enforcement action.
No reply to this letter is required. If you choose to reply, in your correspondence please refer
to CPF 5-2019-2002W. Be advised that all material you submit in response to this
enforcement action is subject to being made publicly available. If you believe that any
portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b),
along with the complete original document you must provide a second copy of the document
with the portions you believe qualify for confidential treatment redacted and an explanation of
why you believe the redacted information qualifies for confidential treatment under 5 U.S.C.
552(b).
Sincerely,
Chris Hoidal
Acting Director, Western Region
Pipeline and Hazardous Materials Safety Administration
cc: David S. Wilkins, Senior Vice President, Alaska
Erin McKay, Regulatory Compliance Manager Alaska Integrity Group
PHP-60 Compliance Registry
PHP-500 M. Chard, T. Johnson (#152927)
7

520192002W_Consent Agreement and Order_05182020_text.pdf

May 18, 2020
VIA ELECTRONIC MAIL TO: dwilkins@hilcorp.com
Mr. David S. Wilkins
Senior Vice President
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
CPF Nos. CPF 5-2019-2001; 5-2019-2002W
Dear Mr. Wilkins:
Enclosed please find a Consent Order incorporating the terms of the Consent Agreement between
the Pipeline and Hazardous Materials Safety Administration (PHMSA) and Hilcorp Alaska, LLC,
which was executed on May 18, 2020. Service of the Consent Order and Consent Agreement by
electronic mail is deemed effective upon the date of transmission as provided under 49 C.F.R.
§ 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Alan K. Mayberry
Associate Administrator
for Pipeline Safety
Enclosure: Order, Consent Agreement, and Compliance Plan
cc: Mr. Dustin Hubbard, Director, Eastern Region, Office of Pipeline Safety, PHMSA
Ms. Linda Daugherty, Deputy Associate Administrator for Field Operations, PHMSA
Mr. David Hassell, Operations Supervisor, Western Region – Alaska, PHMSA
Ms. Denali Kemppel, General Counsel, Hilcorp Alaska, LLC, dkemppel@hilcorp.com
Mr. Justin Furnace, Vice President, Government and Public Affairs, Hilcorp Energy
Company, jfurnace@hilcorp.com
Mr. James Curry, Outside Counsel, Babst Calland, jcurry@babstcalland.com
CONFIRMATION OF RECEIPT REQUESTED



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
In the Matter of )
)
)
Hilcorp Alaska, LLC, ) CPF Nos. 5-2019-2001;
) 5-2019-2002W
Respondent. )
____________________________________)
CONSENT ORDER
By letter dated January 24, 2019, the Pipeline and Hazardous Materials Safety Administration
(PHMSA), Office of Pipeline Safety, issued a Notice of Probable Violation (Notice) to Hilcorp
Alaska, LLC (Hilcorp or Respondent). By letter dated January 25, 2019, PHMSA issued a
Warning Letter to Respondent.1
In accordance with 49 C.F.R. § 190.239, the Notice alleged that Hilcorp reported the Middle
Ground Shoal (MGS) gas pipeline system located in the waters of the Upper Cook Inlet as
onshore, rather than offshore transmission mileage, in its 2015 Annual Report. The Director
proposed a civil penalty of $198,700 for this alleged violation and proposed that the Respondent
take certain corrective measures to remedy the alleged violation. Also, on January 25, 2019, the
Director issued a Warning Letter (Warning) to Hilcorp alleging nine probable violations of the
pipeline safety regulations with regard to the MGS system.
In response to the Notice and Warning Letter, Respondent timely requested a hearing and an
informal discussion concerning potential settlement of the dispute. The parties subsequently
engaged in good-faith settlement discussions that have resulted in the Consent Agreement and
Compliance Plan attached to this Consent Order that settles all of the allegations in the Notice
and Warning Letter.
Accordingly, the Consent Agreement and Compliance Plan is hereby approved and incorporated
by reference into this Consent Order. The Respondent is hereby ordered to comply with the
terms of the Consent Agreement, effective immediately.
Pursuant to 49 U.S.C. 60101, et seq., failure to comply with this Consent Order may result in the
assessment of civil penalties of up to $200,000, as adjusted for inflation (see 49 C.F.R.
§ 190.223), for each violation for each day the violation continues or in referral to the Attorney
General for appropriate relief in a district court of the United States.
1 Pursuant to 49 C.F.R. § 190.205, Warning Letters are not adjudicated. However, in this case, resolution of the
Warning Letter is specifically referenced in the Consent Agreement and is therefore referenced in this Order as well.



The terms and conditions of this Consent Order are effective upon service in accordance with
49 C.F.R. § 190.5.
_____________________________ ________________________
Alan K. Mayberry Date
Associate Administrator
For Pipeline Safety



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
In the Matter of )
) CPF Nos. 5-2019-2001;
Hilcorp Alaska, LLC, ) 5-2019-2002W
Respondent. )
)
)
)
SETTLEMENT AGREEMENT
Starting in 2015, Hilcorp Alaska, LLC (Hilcorp or Respondent) and the Pipeline and Hazardous
Materials Safety Administration (PHMSA) (collectively, the Parties) began discussing the
jurisdictional status and regulatory classification of Hilcorp’s pipelines in and around the Upper
Cook Inlet. Hilcorp raised this issue with PHMSA and sought clarity on the status of these assets
after acquiring them from a number of other operators. Hilcorp maintained that certain assets
located within the waters of the Upper Cook Inlet were exempt from the regulatory requirements
of 49 C.F.R. Parts 192 and 195. PHMSA informed Hilcorp that it disagreed with that position and
maintained that the assets were subject to PHMSA’s regulatory oversight.
On October 31, 2018, PHMSA issued a report titled “Inventory of Upper Cook Inlet Pipeline
Facilities and Identification of Regulators” (Inventory). The Inventory identified federal and state
agencies with regulatory authority over pipelines located in the waters of the Upper Cook Inlet,
listed current pipeline operators and assets in those waters, and made statements regarding
PHMSA’s views concerning the jurisdictional status of the assets.
On January 24, 2019, the Director, Western Region, PHMSA Office of Pipeline Safety, (Director)
issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order
(Notice) to Hilcorp. The Notice alleged that Hilcorp reported the Middle Ground Shoal (MGS)
gas pipeline system located in the waters of the Upper Cook Inlet as onshore, rather than offshore
transmission mileage, in its 2015 Annual Report. The Director proposed a civil penalty of
$198,700 for this alleged violation and proposed that the Respondent take certain corrective
measures to remedy the alleged violation. Also, on January 25, 2019, the Director issued a
Warning Letter (Warning) to Hilcorp alleging nine probable violations of the pipeline safety
regulations with regard to the MGS system.
On January 25, 2019, Hilcorp filed a Petition for Review in the United States Court of Appeals for
the D.C. Circuit, No. 19-1016, challenging PHMSA’s statements of jurisdiction and regulatory
oversight in the Inventory (Petition).
Hilcorp timely responded to the Notice and Warning, contested that the pipeline in question was
properly classified as “offshore”, and requested a hearing and an informal discussion concerning
Page 1 of 12



potential settlement of the dispute. The Parties have reached an agreement that settlement of these
proceedings will avoid further administrative proceedings or litigation, that entry into this
Settlement Agreement (Agreement) is the most appropriate means of resolving the issues raised in
the Notice, and addressing any findings from PHMSA inspections of the Covered Pipelines
(defined below) that occurred before the Effective Date of this Agreement, and that the Agreement
is in the public interest. Therefore, pursuant to 49 C.F.R. Part 190, without adjudication of any
issue of fact or law, and upon consent and agreement of Hilcorp and PHMSA, the Parties agree as
follows:
I. General Provisions
Acknowledgements. Hilcorp acknowledges that as of the Effective Date of this
Agreement Hilcorp, as the operator of certain pipeline facilities that transport hazardous liquids
and natural gas in the Upper Cook Inlet, is subject to the jurisdiction of the Federal Pipeline Safety
Laws, 49 U.S.C. § 60101, et seq., and the regulations and administrative orders issued thereunder.
Specifically, Respondent acknowledges the following:
a. The Submerged Gathering Pipelines, Out-of-Service Pipelines, and the Kenai
Katchemak Pipeline as defined in Table 1 of this Agreement, are subject to the
jurisdiction of the Federal Pipeline Safety Laws, 49 U.S.C. § 60101, et seq., and
the regulations and administrative orders issued thereunder.
b. The Onshore Gathering Pipeline as defined in Table 1 of this Agreement as the
West Cook Inlet Gas Gathering System, is subject to the jurisdiction of the Federal
Pipeline Safety Laws, 49 U.S.C. § 60101, et seq., and the regulations and
administrative orders issued thereunder, but only with regard to the portions of that
pipeline that qualify as a regulated gathering line under PHMSA’s gas gathering
regulations.
c. For purposes of this Agreement, Hilcorp acknowledges that it received proper
notice of PHMSA’s actions in these proceedings.
Scope of this Agreement. This Agreement applies to Respondents’ Submerged
Gathering Pipelines, Kenai Katchemak Pipeline and the regulated portions of the Onshore
Gathering Pipeline (“Covered Pipelines”) as defined in Table 1 of this Agreement. This
Agreement also creates separate requirements applicable to the Out-of-Service Pipelines, as
defined in Table 1 of this Agreement, which are set out in Section II of the Compliance Plan –
Plan for Out of Service Pipeline Facilities. This Agreement does not apply to Respondent’s
unregulated Production Pipelines, the unregulated portions of the Onshore Gathering Pipeline
as defined in Table 1 of this Agreement, or the unregulated Dolly Varden C pipeline, as the Parties
agree that these pipelines are not subject to PHMSA’s jurisdiction. The Agreement does not apply
to any other assets not specifically identified in this Agreement.
Page 2 of 12



Table 1
Submerged Gathering Pipelines
Pipeline Name
Pipeline Description
Pipeline Regulatory
Classification
Monopod A
8-inch oil pipeline from
Regulated Offshore
Monopod Platform to Trading
Gathering
Bay Production Facility
(TBPF)
Dolly Varden A
8-inch oil pipeline from Dolly
Regulated Offshore
Varden Platform to TBPF
Gathering
Anna A
8-inch oil pipeline from Anna Regulated Offshore
Platform to Bruce Platform
Gathering
Bruce GP-1
6-inch oil pipeline from
Regulated Offshore
Bruce Platform to Granite
Gathering
Point Tank Farm (GPTF)
Granite Point B
8-inch oil pipeline from
Regulated Offshore
Granite Point Platform (GPP)
to GPTF
Gathering
Steelhead B
10-inch gas pipeline from
Regulated Offshore
Steelhead Platform to TBPF
Gathering
Monopod B
8-inch gas pipeline from
Regulated Offshore
TBPF to Monopod Platform
Gathering
Dolly Varden B
8-inch gas pipeline from
Regulated Offshore
TBPF to Dolly Varden
Gathering
Platform
Grayling B
10-inch gas pipeline from
Regulated Offshore
TBPF to Grayling Platform
Gathering
King Salmon B
8-inch gas pipeline from
Regulated Offshore
TBPF to King Salmon
Gathering
Platform
Anna B
8-inch gas pipeline from
Regulated Offshore
Bruce Platform to Anna
Gathering
Platform
Bruce GP-2
6-inch gas pipeline from
Regulated Offshore
GPTF to Bruce Platform
Gathering
Granite Point A
8-inch gas pipeline from
Regulated Offshore
GPTF to GPP
Gathering
2 As used in this Agreement, Submerged Gathering Pipelines refers only to the submerged portions of the pipelines
listed in Table 1. The Parties recognize that there are relatively short, onshore portions of the Submerged Gathering
unregulated gas gathering lines under 49 C.F.R. § 192.8. The onshore portions of the liquid Submerged Gathering
Pipelines listed in Table 1. The onshore portions of the gas Submerged Gathering Pipelines are currently Class 1
§ 195.11.
Pipelines are all rural gathering lines that do not meet the definition of regulated rural gathering line in 49 C.F.R.
Page 3 of 12



Spark B
6-inch gas pipeline from
Regulated Offshore
Granite Point Production
Gathering
Facility (GPPF) to Spark
Platform
Spark Spurr Intertie
6-inch gas pipeline from
Regulated Offshore
Spark Platform to Spurr
Gathering
Platform
Out-of-Service Pipelines
Pipeline Name
Pipeline Description
Pipeline Regulatory
Classification
Dillon B
8-inch oil pipeline from
Out of Service
Platform C to Dillon Platform
Dillon D
8-inch gas pipeline from
Out of Service
Dillon to East Foreland
Facility
Baker A
8-inch gas pipeline from
Out of Service
Baker Platform to Platform
A.
Spurr Gas
6-inch gas pipeline from
Out of Service
Spurr Platform to GPPF
Spurr Oil
6-inch oil pipeline from Spur Out of Service
Platform to GPPF
Steelhead A
10-inch gas pipeline from
Out of Service
Steelhead Platform to TBPF
Kenai Katchemak Pipeline (KKPL)
Pipeline Name
Pipeline Description
Pipeline Regulatory
Classification
Kenai Katchemak Pipeline
12-inch gas pipeline that
Gas transmission
originates at the KKPL Tie-ln
Pad and terminates at the
Kenai Gas Field 33-30 Pad.
Onshore Gathering Pipeline
Pipeline Name
Pipeline Description
Pipeline Regulatory
Classification
West-Cook Inlet Gas
16-inch gas pipeline from the | Onshore Gathering (Class 1
Gathering System (W-
TBPF to the terminus at a tie- unregulated)
CIGGS)
Page 4 of 12



in with the Beluga gas
transmission pipeline
Production Pipelines
Pipeline Name
Pipeline Description
Pipeline Regulatory
Classification
Grayling A
10-inch oil pipeline from
Production
Grayling Platform to TBPF
King Salmon A
8-inch oil pipeline from King
Production
Salmon Platform to TBPF
Steelhead C
8-inch oil pipeline from
Production
Steelhead Platform to TBPF
Platform A - B1
8-inch oil pipeline from
Production
Platform A to East Foreland
Facility
Platform C - B2
8-inch oil pipeline from
Production
Platform C to Platform A
Happy Valley
6-inch gas pipeline from
Production
Happy Valley Pad B to
Happy Valley Pad A and then
to KKPL Tie-In Pad
Paxton
8-inch gas pipeline from
Production
Paxton Pad to KKPL
Susan Dionne
8-inch gas pipeline from
Production
Susan Dionne to KKPL
Ninilchik State
8-inch gas pipeline from
Production
Ninilchik State Pad to KKPL
George Oskoloff (GO)
8-inch gas pipeline from GO
Production
Pad to KKPL
Bartolowits
6-inch gas pipeline from
Production
Bartolowits Pad to KKPL
Falls Creek
8-inch gas pipeline from Falls
Production
Creek Pad to KKPL
Kasilof Extension
6-inch gas pipeline from
Production
Bartolowits Pad to KKPL
Respondent agrees to complete the actions specified in Attachment A to this
Agreement (Compliance Plan) and to abide by the terms of this Agreement. The Compliance
Plan is incorporated by reference into this Agreement. This Agreement does not constitute a
finding of violation of any law or regulation and may not be used in any civil, criminal, or
administrative proceeding of any kind as evidence or proof of any fact, fault or liability, or as
evidence of the violation of any law, rule, regulation or requirement, except in a proceeding to
enforce the provisions of this Agreement.
Page 5 of 12



After Respondent returns this signed Agreement to PHMSA, the Agency’s
representative will present it to the Associate Administrator for Pipeline Safety, recommending
that the Associate Administrator adopt the terms of this Agreement by issuing a Consent Order
pursuant 49 C.F.R. § 190.219 incorporating the terms of this Agreement. The terms of this
Agreement constitute an offer of settlement until accepted by the Associate Administrator. If the
Associate Administrator accepts, the Associate Administrator will issue a Consent Order
incorporating the terms of this Agreement.
Respondent consents to the issuance of the Consent Order, and hereby waives any
further procedural requirements with respect to its issuance. Respondent waives all rights to
contest the adequacy of the Notice, or the validity of the Consent Order or this Agreement,
including all rights to administrative or judicial hearings or appeals, except as set forth herein.
This Agreement shall apply to and be binding upon PHMSA, and upon Hilcorp, its
officers, directors, and employees, and its successors, assigns, or other entities or persons
otherwise bound by law. Hilcorp agrees to provide a copy of this Agreement and any incorporated
work plans and schedules to all of Hilcorp’s officers, employees, and agents whose duties might
reasonably include compliance with this Agreement.
For all transfers of ownership or operating responsibility of the Covered Pipelines,
Hilcorp will provide a copy of this Agreement to the prospective transferee at least 30 days prior
to such transfer. Hilcorp will provide written notice of a transfer of ownership or operating
responsibility to the Director within 30 days after such transfer. This provision shall not apply to
any of those facilities that have been abandoned in accordance with 49 C.F.R. §§ 192.727 or 195.59
at or before the time of the transfer.
This Agreement constitutes the final, complete, and exclusive agreement and
understanding between the Parties with respect to the settlement embodied in this Agreement. The
Parties acknowledge that there are no representations, agreements or understandings relating to
settlement other than those expressly contained in this Agreement.
Nothing in this Agreement affects or relieves Respondent of its responsibility to
comply with all applicable requirements of the Federal Pipeline Safety Laws, 49 U.S.C. § 60101,
et seq., and the regulations and orders issued thereunder; and nothing in this Agreement alters
PHMSA’s right of access, entry, inspection, and information gathering or PHMSA’s authority to
bring enforcement actions against the Respondent pursuant to the Federal Pipeline Safety Laws,
the regulations and orders issued thereunder, or any other provision of Federal or State law; with
the following mutual understandings regarding timing:
a. The Parties agree that, to allow Hilcorp time to integrate the Covered Pipelines into
its PHMSA compliance programs, PHMSA’s inspections of the Covered Pipelines
during the pendency of this Agreement will be limited to inspections to verify
compliance with this Agreement and to investigate and address existing or
imminent safety conditions or concerns.
Page 6 of 12



b. The Parties agree that nothing in this Agreement prevents PHMSA from
investigating a pipeline accident or incident on any Hilcorp pipeline facilities
subject to PHMSA’s jurisdiction, or employing its Corrective Action Order or
Safety Order authorities under 49 U.S.C. §§ 60112 and 60117(l), respectively.
c. The Parties agree that, in light of the challenges associated with the jurisdictional
status and regulatory classification of the Covered Pipelines, and the Parties’ long-
running discussions of the same, PHMSA will not bring enforcement actions for
alleged violations of the Pipeline Safety Laws or PHMSA’s Pipeline Safety
Regulations that may have occurred with respect to the Covered Pipelines prior to
the Effective Date.
d. The Parties agree that during the pendency of this Agreement, PHMSA will not
bring enforcement actions against Hilcorp regarding alleged violations of the
Pipeline Safety Laws or PHMSA’s Pipeline Safety Regulations that may occur with
respect to the Covered Pipelines, except that PHMSA may bring an enforcement
action with regard to alleged violations for failing to comply with the terms of this
Agreement.
e. Notwithstanding subparagraph (d) of this paragraph, the Parties agree that PHMSA
may commence normal inspection and enforcement activities for the activities
covered in the Compliance Plan on expiration of the various compliance
timeframes as set forth in the Compliance Plan.
This Agreement does not waive or modify any Federal, State, or local laws or
regulations that are applicable to Hilcorp’s pipeline systems. This Agreement is not a permit, or a
modification of any permit, under any Federal, State, or local laws or regulations. Respondent
remains responsible for achieving and maintaining compliance with all applicable Federal, State,
and local laws, regulations, and permits.
This Agreement does not create rights in, or grant any cause of action to, any third
party not party to this Agreement. The U.S. Department of Transportation is not liable for any
injuries or damages to persons or property arising from acts or omissions of Respondent or its
officers, employees, or agents carrying out the work required by this Agreement. Respondent
agrees to hold harmless the U.S. Department of Transportation, its officers, employees, agents,
and representatives from any and all causes of action arising from any acts or omissions of
Respondent or its contractors in carrying out any work required by this Agreement.
Should a change in law, regulation, or operational status of any of the pipelines
identified in Table 1 occur that may affect the jurisdictional status or regulatory classifications of
the pipeline facilities subject to this Agreement, either Party may notify the other of such potential
change, and the Parties agree to discuss any potential classification changes in good faith.
The Director may grant an extension of time for compliance with any of the terms
of this Agreement, including the Compliance Plan, upon a written request timely submitted
demonstrating good cause for an extension. Absent unexpected delays, Hilcorp will submit any
Page 7 of 12



requests for extension no less than 30 days before the applicable deadline. The Director shall
respond to any such requests within 14 business days of receipt.
II. Monetary Penalties
In consideration of the good faith nature of this Agreement, PHMSA hereby
withdraws the allegation and proposed civil penalty of $198,700 in Item 1 of the Notice for CPF
No. 5-2019-2001.
If Hilcorp commits a Material Breach of this Agreement, as defined in Paragraph
16, Hilcorp will be liable for stipulated penalties, unless a force majeure event has occurred in
accordance with Section VI (Force Majeure), according to the following provisions:
a. For each Material Breach of this Agreement, Respondent will pay $750 per day for
each instance of failure to comply for the first 15 days of noncompliance; $1000
per day for the 16th through 30th days of noncompliance; and $1,250 per day for
each day of noncompliance thereafter.
b. Stipulated penalties under this Paragraph will begin to accrue on the day after
performance is due, and shall continue to accrue through the final day of completion
of the activity.
c. Respondent will pay any stipulated penalties not more than 30 days after receipt of
written demand by PHMSA for such penalties. Federal regulations (49 C.F.R. §
89.21(b)(3)) require payments in excess of $10,000 dollars to be made by wire
transfer through the Federal Reserve Communications System (Fedwire) to the
account of the “U.S. Treasury.”
A Material Breach of this Agreement shall be the Respondent’s failure to complete
certain activities required in the Compliance Plan, as specified below, by the deadline established
in the Compliance Plan combined with a failure to obtain a time extension for such activity from
PHMSA. Should Hilcorp appeal a PHMSA decision regarding a time extension pursuant to
Paragraph 23, no Material Breach shall occur until the Associate Administrator issues a
determination with respect to that appeal
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