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Foster Report No. 3036 February 6, 2015

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FOSTER REPORT NO. 3036 February 6, 2015

i © Concentric Energy Publications, Inc.

Published by Concentric Energy Publications, Inc., a Concentric Energy Advisors, Inc. Company

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February 6, 2015 FOSTER REPORT NO. 3036

© Concentric Energy Publications, Inc. ii

TABLE OF CONTENTS

FERC

FERC Positions Itself to Be Honest Broker As Public Outcry Takes a More Activist Course, According to Chairwoman LaFleur 1

FERC Submits Fiscal Year 2016 Budget Request of $320 Million to Congress -- 5% Increase Over 2015 Budget 3

FERC POLICY – GAS DAY DEBATE

Natural Gas Industry Uniformly Tells FERC that Data Provided by Electric Grid Operators Fail to Support Any Change to the Start of the Customary Gas Day 5

With Several Recommendations, State Regulators Offer Support and in Some Cases Caution for FERC’s Proposal Regarding Gas Pipeline Recovery of Modernization Costs; PHMSA Recommends Broad Use of Pipeline Modernization Programs 10

FERC ENFORCEMENT

FERC Majority Brings Enforcement Action Against Canadian-Managed U.S. Power Generator That Allegedly Sought to Collect ISO-New England Reimbursements for Standby Role Based on High Fuel Oil Costs When In Fact Cheaper Natural Gas Was Used and Available 15

NATURAL GAS PROJECTS

Pre-filing Review Begins at FERC for the Atlantic Bridge Project, Joined by Algonquin and Maritimes & Northeast Pipeline 18

Tennessee Gas Pipeline Submits FERC Application Seeking Authorization for Broad Run Expansion Project To Deliver Marcellus/Utica Shale Gas Produced by Antero Resources 20

Constitution Blasts Opponents of Its Certificated Constitution Pipeline and Wright Interconnection Projects; In Context of the Clean Water Act, Is a FERC Pipeline Certificate the Equivalent of a License or Permit? 22

Peoples LDCs Object to Proposal of Equitrans to Establish a Zone to Manage Services on Proposed Ohio Valley Connector 26

NATURAL GAS PIPELINE TARIFFS

No FERC Policy Requires ANR Pipeline to Give Original Natural Gas Shipper a Right to Match in Open Season Bidding for Capacity Requested by that Shipper; Commission Addresses Matching Right of Shippers Holding Longer Term Pre-Arranged Deals 27

FERC Accepts a Rate Schedule IBS (Interruptible Balancing Service) Proposed by Equitrans, Subject to Clarification Sought by Peoples’ LDCs 29

Widely Protested Tariff Changes, Including New Imbalance and Flow Management Service and Penalties, Sought by MoGas Pipeline Are Set By FERC for Technical Conference 30

OIL PIPELINE PROJECTS

FERC Determines in Favor of Enbridge Energy’s Scheme to Recover Costs of Its Four-Part Midwestern Project 24, Despite Reservations Aired by Suncor Marketing and Flint Hills Resources 32

ENERGY NEWS ALERT 35

EIA’S GAS STORAGE AND WEEKLY ANALYSIS 42


1 © Concentric Energy Publications, Inc.

FERC

FERC Positions Itself to Be Honest Broker As Public Outcry Takes a More Activist Course, According to Chairwoman LaFleur

FERC is facing new challenges, in a world of growing natural gas production, an increase in gas-fired electricity generation, multiplying environmental

regulations, cyber threats and electric grid reliability concerns, the Commission’s Chair Cheryl LaFleur told a Washington D.C. audience at the National Press Club (NPC) on January 26.

NPC’s president, John Hughes, introduced LaFleur was the first Commission Chairperson to speak at the Club. In some sense her wide-ranging talk and affable interaction with the audience was in keeping with her reputation for being accessible and approachable (see FR for the publication’s interview with her when she became a Commissioner in 2010). LaFleur will serve as Chairwoman several more months – until she switches places with Norman Bay who assumes the post on April 15. She affirmed her plan to remain at the Commission through the second term, which ends in 2019.

LaFleur described herself as an “energy lifer,” with 30 years in the business. Five years ago when she was appointed, FERC was not a household name. Now with energy issues gaining such prominence in the U.S., along with an increased level of activism and protests against the Commission itself, FERC “is in the spotlight. The Commission must maintain a proper course of action, continue to do the daily work of carrying out its regulatory duties, bound by statute,” LaFleur affirmed.

“Examining the underbelly of every energy issue is unsexy, but it is what we do best,” she explained. FERC must balance a trio of core issues when looking at energy projects: reliability, cost, and the environment. How to strike a balance amongst the “cacophony” of different voices is FERC’s charge. Making progress towards this balance requires “real conversations regarding the tradeoffs,” the Chairman continued.

“FERC is not an environmental regulator,” LaFleur stressed. It really is up to the Environmental Protection Agency (EPA) and the states to govern environmental policies. Even so, the Commission will have an active part in implementation of the EPA’s Clean Power Plan (CPP). “Make no mistake, FERC will have a role to play in the CPP’s implementation. I believe that as a nation we can achieve real environmental progress, but only if we can build the necessary infrastructure, both gas and electric, and build the necessary energy markets to make that possible.”

LaFleur suggested that FERC’s role will center on three areas: infrastructure, markets, and being an “honest broker for discussions.” Over the last several months, the Commission has seen “a steady stream of visitors presenting a wide range of views on the CPP,” she acknowledged.

The Commission scheduled several technical conferences to discuss implications of the compliance approaches to the CPP, focusing on electric reliability, wholesale electric markets and operations, and energy infrastructure. A February 19th meeting at FERC’s headquarters will be a national overview, while three additional conferences will focus on regional issues and be staff led. Those conferences are slated to be held in the: (1)Western Region – February 25 in Denver, Colorado; (2) Eastern Region – March 11 in

Source: FERC


© Concentric Energy Publications, Inc. 2

Washington, DC; and (3) Central Region – March 31 in St. Louis, Missouri.

LaFleur expects the energy industry to increase its utilization of generating plants to reduce emissions. This will lead to the construction of new gas-fired power plants, as gas plants are currently most cost-effective. “Natural gas is enabling us to meet our climate goals,” LaFleur stressed. “But gas does have its own issues,” she added. The building of additional pipelines and compressors will be critical. The Commission also is seeing an unprecedented level of activism against the fuel’s production and pipeline siting (see FR No. 3034, pp4-6).

Referring to the recent disruptions at the Commission’s headquarters, both outside and even within the public meeting room, the Chairwoman affirmed that the perpetrators do have their place in the Commission-monitored siting process, and they should play a role, “as these are important issues.” In its siting role under the Natural Gas Act, FERC takes the input of all stakeholders “very seriously.” However, she reiterated that their choice of venue and methods are only disruptive and not consistent with the historical and actual role that the Commission plays.

Within the standard system, FERC is seeing an uptick in the number of filings and advocacy by individuals and the Commission’s Secretary is doing a great job of processing the comments, according to LaFleur. In general, protestors usually are concerned about (1) how pipelines impact the environment; (2) pipeline routes in the vicinity of their local communities; or (3) the greater/or lesser need for pipelines and/or energy production.

Regarding how pipeline construction affects the environment, FERC “must do this right,” LaFleur agreed. Pipelines must be constructed carefully, using the most environmentally-advanced techniques. For

siting, the Commission must carefully route pipes through communities, and this is “something FERC does well.” Very few pipelines come out of FERC’s siting process with the same route that was originally proposed.

As for handling “bigger picture” items, such as whether to “allow” natural gas production or fracking, LaFleur explained that this is outside of FERC’s scope. The Commission does not regulate production or fracking, as these activities remain primarily under scrutiny at the state level. Federal statues dictate that the Commission must consider and act on pipeline applications by assessing the market demand and contractual demand for long-term firm transportation capacity. Under National Environmental Policy Act (NEPA) requirements, the Commission looks closely at the environmental aspects of pipeline siting, including water, soil, and air quality impacts. But this review is “very project-specific,” the Chairman clarified.

Looking ahead, LaFleur acknowledged that “at some point soon the nation is going to have to grapple with” natural gas’ role in helping to meet climate change goals. Moving away from coal-fired generation “and closing down the old stuff” means that the nation will need new generation, the Chairwoman offered. Furthermore, the increased reliance on renewable energy makes generation highly dependent on transmission. Long transmission lines are required to benefit the grid, but the lines don’t benefit everyone, and their siting is also very controversial.

Energy efficiency measures and distributed generation technologies employed under the CPP will also need delivery systems. Having implemented “conservation” programs previously, LaFleur knows that those kinds of programs “are not free, nor are they self-executing.”



Implementation of the CPP as a whole could be very complicated. States will be able to develop different plans, deciding on what energy sources they will use. However, a state’s resource mix may not automatically be compatible with existing infrastructure, creating a need to reconcile differences, which on a larger scale increases the complexity.

For example, in the Mid-Atlantic’s PJM power region of 13 states, each state could come up with substantially different portfolios, and the system operator would have to dispatch power based on those 13 different plans. EPA, based on input from FERC, would allow extra credit for states and regions to work together, but the process could represent “considerable change and compromise.”

As far as FERC getting authority to “sign off” on state plans, LaFleur believes that level of approval is “a bit strong.” States ultimately must have control, she insisted. If Congress changes FERC’s mandate, “of course the agency will respond.” Yet, she holds, “we are well served having EPA and the states regulate the environment, and having a healthy division of responsibility. FERC has its own role.”

Nonetheless, with generation mix changes, FERC still must enforce market rules and market designs that are necessary for reliability, and “this requires open dialogue,” LaFleur noted. So it follows that FERC’s role as an honest broker in the forthcoming discussion is important. At the upcoming CPP conferences, the Commission will bring together state government partners and other stakeholders to discuss compliance issues associated with the rule. “This will be just the beginning of the dialogue,” according to the FERC Chairwoman. “And we can’t be afraid to say the hard things in regard to these difficult policy issues.”

FERC Submits Fiscal Year 2016 Budget Request of $320 Million to Congress -- 5% Increase Over 2015 Budget

On Feb. 2 FERC Chairman Cheryl LaFleur submitted to Congress FERC’s Fiscal Year (FY) 2016 budget request of $320 million, an increase of about $15.4 million over last FY’s budget of $304.4 million or 5%. Since FERC recovers the full costs of its operations through annual charges and filing fees from the industries it regulates, the appropriation request funds necessary expenses in advance until its fee revenues deposited into the Treasury Department offset the appropriation, resulting in a net appropriation of zero.

To execute its mission in fiscal year (FY) 2016, the budget would fund 1,480 full-time equivalent (FTE) employees. To fund activities associated with ensuring just and reasonable rates, the Commission requested 702 FTEs (the same as last year) and $149 million for FY 2016, a funding increase of 4.5%. FERC requested $112.5 million and 498 FTEs (the same as last year) for its role of promoting safe and reliable infrastructure, a 6.1% increase over FY 2015 funding levels. To assist FERC in operating in an efficient, responsive and transparent manner -- including its headquarters’ modernization project, managing its employees, upgrading its e-library record system, and implementing a pilot cloud-based storage program -- the Commission requested 280 FTEs and $58.3 million in funding, a 4.6% increase.

FERC’s natural gas regulation activities would receive 282 FTEs, the same level as in FY 2015, along with funding of $61 million, a 2.9% decrease compared to FY 2015.

The request reflects the necessary resources to support mandatory increases in salaries and benefits associated with a 1.0% pay raise in FY 2016. In addition, the budget would fund the $7 million increase in rent (or 29%)



at its headquarters building on 888 First Street, Washington D.C., as a result of renewing a 10-year lease with an increased rental rate.

Congress approved FERC’s prospectus of the ten-year lease option, but is requiring the Commission to consolidate to reduce its overall headquarters building space utilization by 12%, which would include relocating employees currently located at 1100 First Street back to FERC Headquarters.

The Commission also anticipates program cost increases associated with statutorily required hydropower environmental workload and expert witness contractor assistance in the Commission’s enforcement program.

Separate from regular operating expenses, the 2016 budget request also includes additional funding for its existing, four-year $50 million building modernization project, including $2.5 million to fund furniture, information technology and security equipment, logistical services, and administration costs. The Commission is expecting to fund $19.7 million of the project in FY 2015 using available prior year budget authority.

Source: FERC Congressional Performance Budget Request, Fiscal Year 2016



FERC POLICY – GAS DAY DEBATE

Natural Gas Industry Uniformly Tells FERC that Data Provided by Electric Grid Operators Fail to Support Any Change to the Start of the Customary Gas Day

According to the opinion of many natural gas industry companies and organizations, in filings made at FERC on or about Feb. 2, data provided to the Commission by U.S. electric grid operators do not make a case for changing the start of the Gas Day. The statistics from the six regional transmission organizations (RTOs) and independent system operators (ISOs)1 “clearly confirm” that there is not a nationwide problem during the morning electric load ramp up that is associated with the current start time, claimed the New England Local Distribution Companies (LDCs), American Public Gas Association (APGA), Natural Gas Council (NGC), and Coalition for Enhanced Electric and Gas Reliability, in separate filings. The problems, “if they exist,” occur mainly in the Northeast, in the view of some.

While some of the data submitted at the request of FERC illustrate that gas-fired power generators experienced outages related to fuel in the past, the gas organizations insisted there was no data indicating that the cause of the lack of fuel was related to the Gas Day. In addition, according to them, the data reveal that there was no measured increase in outages during the morning ramp period than at other times during the day.

In the commenters’ view, the Commission lacks the record of evidence required under

1 PJM Interconnection, LLC (PJM); Southwest Power Pool,

Inc. (SPP); ISO New England Inc.; Midcontinent Independent System Operator, Inc. (MISO); New York Independent System Operator, Inc. (NYISO); and California Independent System Operator Corp. (CAISO) all filed data as requested at FERC.

the section 5 of the Natural Gas Act (NGA) to justify changing the start of the Gas Day from 9:00 a.m. Central Clock Time (CCT) to 4:00 am CCT. The NGC’s comments, anchored by a group of ten natural gas industry-related associations2, questioned the data filings, claiming that the information failed to provide a sufficient record evidence for the Commission to move the Gas Day start. The RTO/ISO responses “confirm” that there is no nationwide issue associated with a 9:00 am CCT start time, and as such FERC should retain the 9:00 am national standard.

Given the dearth of evidence, the NGC stated: “Now that FERC’s attention is finally focused on addressing regional power market fuel assurance improvements,” the gas industry’s hope is that “both the Commission and RTOs/ISOs will recognize that changing the start of the Gas Day is not the answer to creating measured improvements in fuel assurance.” RTOs/ISOs are “actively” pursuing regional solutions already, and these “are working,” the Electric and Gas Reliability Coalition suggested.

As part of its proceedings in RM14-2, the Commission is concerned that the current start of the Gas Day occurs in the middle of the morning ramp in some regions, “creating a situation where electric load is increasing at the same time natural gas-fired generators may be running out of their daily nominations of natural gas transportation service.” FERC proposed in a Notice of Proposed Rulemaking (NOPR) to move the start of the Day earlier, in part to address instances in which those generators reduce their electric output (or de-rate) during the morning ramp period in order to balance their remaining scheduled natural gas transportation capacity for that day.

2 The following groups made the joint filing: The American

Forest & Paper Association; the American Gas Association; America’s Natural Gas Alliance; the American Public Gas Association; the Gas Processors Association; the Independent Petroleum Association of America; the Interstate Natural Gas Association of America; the Process Gas Consumers Group; and the Texas Pipeline Association.



After receiving a barrage of comments from all sides of the Gas Day debate in late November (FR Nos. 3031, pp15-25; 3031, pp13-15; and 3028, pp4-14), FERC’S Office of Energy Policy and Innovation (OEPI) sent letters to the RTOs/ISOs on Dec. 12, requesting information on generators running out of their daily nominations during the morning electric ramp -- to the extent this occurs in their regions.3

Details of the Responses. The comments on the data from the gas industry all overwhelmingly assert that the grid operators have not demonstrated a “causal link” between generator de-rate issues and the current start time of the Day. Furthermore, the Commission’s data requests had failed to seek information regarding the type of gas supply arrangements made by the generators who de-rated their capacity. Without that information, the gas parties argued that the Commission cannot fully understand the reasons for de-rates and the behavior of generators. In addition, if shippers do not contract for sufficient transportation capacity, supply or swing services to meet its electric burn obligation, a de-rate problem would exist irrespective of when the Gas Day begins. Generators in a region relying only on interruptible contracts thus “should bear the risks and should not force changes to the nationwide energy industry simply as a result of the choices.”

Gas Council. Three regions indicated no issue with their morning electric ramp associated with the current Gas Day, noted the NGC. CAISO stated that it “has not located any record of a natural gas-fired generator notifying the CAISO that the generator had to de-rate a unit during the hours of 3:00 am and 9:00 am CCT because the generator exhausted its daily nomination of natural gas

3 FERC requested the data submissions by Jan. 22 (after

extending the deadline by 10 days as desired by the RTOs/ISOs) and requested comments in response to the data filings by Feb. 2.

transportation service prior to the end of the gas day.” Natural gas-fired generators operating in the CAISO balancing authority generally do not face problems securing sufficient fuel to meet the morning electric ramp under existing electric and gas market timelines.

Similarly, MISO has not experienced any significant impacts caused by generators running out of natural gas during the morning ramp. SPP, while not making a direct assertion as to whether it believes the current start time has impacted generator de-rates in its region, does not collect data that would allow it to accurately assess the underlying causes of de-rates. Also, out of a total of 5,603 outages in SPP during the two-year period (2013-2014), only one-fourth (1,461) of the outages occurred in the morning ramp, which is no more outages during the morning timeframe than the number of outages that occurred during all other hours of the day, declared the Council.

Moreover, the other three RTOs and ISOs failed to show any direct correlation between generator de-rates and the 9:00 am start, since: (1) the data collected is too vague to accurately reflect the true cause of generator outages; (2) the reported outages during the reporting timeframes are not out of proportion with the de-rates experienced during other times of day; and (3) there is no evidence that regional reliability has been impacted by the current Gas Day.

MISO, SPP, PJM and ISO-NE each acknowledged that their current information collection systems were inadequate to provide a level of specificity required to conclude if de-rates occurred due to exhaustion of gas nominations, NGC commented. The systems do not reveal whether outages occurred due to a generator running out of nominated gas, nor do the “cause codes” submitted by PJM and NYISO reveal the actual reasons for the listed instances of outages or de-rates.



The cause codes provided by the generators to PJM and NYISO are “so vague that they are useless for purposes of understanding the root cause of the specific problem experienced by the generators,” the NGC complained. A “lack of fuel” can be attributed to any number of factors, including a generator’s decision not to purchase available supplies if it found that it was not in its economic best interest to do so. Such vague terms could also reflect a generator’s inability or decision not to procure the quantity of delivered gas or the types of arrangements it may have needed to meet its dispatch obligations.

This makes it impossible to determine whether the generators contracted for firm or interruptible transportation, whether they made adequate advance arrangements with marketers or producers to secure delivered gas, or whether the regional operator gave unexpected dispatch orders – and these issues would exist irrespective to the start of the Gas Day.

NGC strongly encouraged grid operators and the Commission “to take a very hard look” to identify how these issues could persist over the long-term for a single generator.

Turning to the instances in which outages were due to a pipeline Operational Flow Order (OFO), NGC argued that that problem too could not be linked to when the Gas Day begins. When a generator de-rates during an OFO, (1) it likely over-relied on the pipeline to provide more flexibility for hourly takes than the generator contractually was entitled to take, and that the pipeline contractually was obligated to provide, or (2) it likely relied on interruptible transportation (and sometimes secondary firm transportation) that subsequently was restricted in order for the pipeline to meet its firm contractual obligations.

Without more specificity in terms of what caused an outage or de-rate for a particular generator, the information provided in these

submissions cannot be relied upon to develop an understanding of the problems experienced by gas-fired generators in their region, let alone to support a change to the start of the Gas Day, NGC concluded. “Unsupported assertions that generators would be ‘better positioned’ with an earlier Gas Day” or data that relies on vague outage codes are not sufficient record evidence to satisfy the Commission’s NGA burden necessary to change the current national 9:00 am start of the nominations process.

Believing that their “collective experience” in the region can assist in providing insight into the ISO-NE’s data responses, the New England LDCs4 similarly told FERC that the ISO’s data “does not demonstrate” that a change in the Gas Day would resolve issues regarding generator de-rates in New England. Moreover, the data responses of ISOs and RTOs in regions outside of the Northeast “make clear” that they have no information supporting a change.

Anyway, prior to moving the start of the day, FERC has a burden under the NGA to show that the existing 9:00 am start time is unjust and unreasonable. The data provided by the ISOs and RTOs “confirms that there is no factual basis upon which the Commission can conclude that the 9:00 am start time is unjust and unreasonable,” the LDCs stated.

Based on the statistics, three of the six RTOs -- CAISO, MISO, and SPP -- had no trouble with generator de-rates during the morning ramp hours, and they are spread throughout the country in the West, Midwest and parts of the South. Since the Northwest, Southwest, and Southeast do not have ISOs and RTOs, the Commission received no data regarding de-rates in those areas. It is only in the Northeast -- in ISO-NE, NYISO, and PJM -- that generators de-rated, and the statistics “simply

4 The New England LDCs have joined the Coalition for

Enhanced Electric and Gas Reliability and support the Coalition’s filed comments on the matter.



do not demonstrate” that de-rates were due to the generators “running out of gas”. Neither NYISO nor PJM reach the conclusion that moving the start of the Day to 4:00 am would reduce the number of generators de-rating during the morning ramp, the New England LDCs stated.

According to the LDCs, NYISO’s data indicates that de-rates were more likely related to limitations on natural gas customers’ ability to receive/take gas, such as OFOs that require gas customers to operate within tight tolerances, or generator-specific issues that might, or might not, be related to the availability of gas supply.

In ISO-NE, the gas utilities said, de-rates occurred on 49 days in 2013 and 2014. However, on 47 of the 49 days (96%) only one or two generators de-rated between 4:00 am and 9:00 am. “Clearly, gas-fired generators in New England are not facing a systemic de-rating problem during the morning ramp period.” In addition, de-rates reflect fairly small reductions in available energy and capacity. ISO-NE’s data show that on 23 of the 49 days on which de-rates occurred (47%), the total reduction was 337 MW or less. As New England has a substantial number of gas-fired generators with a total hourly capability of 13,600 MW, “this reduction is minimal.”

Furthermore, the LDCs suggested there is no correlation between generator de-rates and pipeline OFOs. On the 49 days in which ISO-NE experienced de-rates, pipelines had issued OFOs on only three of those days (6%).

“Thus, generators in the region were not often required to de-rate on days when pipeline capacity was most restricted and balancing would have been the most difficult,” stressed the LDCs. On days when pipelines do not issue OFOs, most shippers have flexibility with respect to gas supply arrangements, so the fact that most de-rates occurred on days without OFOs indicates that the de-rates were

not the result of generators coming up short on gas.

Lastly, the New England-based gas utilities told FERC that they too face their own morning ramps due to natural gas heating loads, yet “to the best of the New England LDCs’ knowledge” the gas utilities faced “no problems” in obtaining sufficient gas to cover the morning ramp period on the exact days that the generator de-rates occurred. LDCs often have firm gas supply arrangements, including firm transportation, storage, and commodity arrangements, in order to ensure that gas supplies will be available when needed – including during morning ramp. “If gas-fired generators lack firm gas supply arrangements, a change in the start of the Gas Day would do nothing to ensure that they can obtain gas supplies when necessary.”

Coalition. Echoing the sentiment of the other commenters, the Coalition for Enhanced Electric and Gas Reliability, which includes scores of local distribution companies (LDCs), combined electric and gas utilities, marketers, and others, also claimed that the data responses lack evidence that moving up the Gas Day start time would improve reliability or enhance electric-gas coordination, mainly because: (1) the RTO/ISO responses did not identify significant, national concerns regarding the start of the Gas Day; (2) the data does not provide sufficient support for changing the existing start; and (3) even in those regions where pipeline capacity constraints and electric-gas coordination challenges exist, efforts are already under way to proactively address the regional concerns, making a change to the start of the Gas Day unnecessary.

Even the ISO-NE, which is the only grid operator that expressed concern about the start of the nominations cycle, was unable to submit data that supported changing the start. That ISO’s data does indicate that generator reductions due to fuel limitations decreased



from 2013 to 2014 by more than 20%, a sign that other solutions being pursued by ISO-NE to address the regional coordination problems are having a positive impact.

The lack of detail from generators, some of which relied on codes from the Generator Availability Data System (GADS), does not allow grid operators to specifically address whether a generator exhausted its daily nomination of gas service anyway.

Without more specific data demonstrating that the current start time is unjust and unreasonable, any change by the Commission at this point would be “legally deficient and open to judicial challenge,” the Coalition believes. Instead, the Coalition claimed it is reasonable to conclude that based on the data provided in this proceeding changing the start of the Gas Day will not have a material, positive impact on electric reliability and “would come at the expense of detrimental reliability, safety and cost impacts.”

With the same message to the Commission, APGA5 stressed that FERC’s data requests “made very clear” what the OEPI staff was looking for: any data not present in the record to support the NOPR Gas Day proposal. The data submitted by the various RTOs/ISOs “does not support the thesis that there is a link between the start of the Gas Day and the reliability of gas-fired generators,” APGA said.

If anything, the record confirms to the APGA the importance of retaining the current start time, accepting the supported changes being proffered to the gas nomination cycles, and directing the electric industry to take important self-help steps to foster greater reliability, “including but not limited to securing firm transportation capacity to move their gas supplies to generators or installing adequate dual fuel capability or investing in

5 In addition to individual comments, APGA also supports

the NGC’s joint comments.

gas storage facilities or making other infrastructure investments to ensure the availability of a firm power supply during peak periods.”

While some RTO/ISOs “were more forthcoming than others” in their responses, “the bottom line” is that none of them has any data reflecting the number or duration of de-rates between 3 am to 9 am due to the generators having exhausted their daily nomination of gas transportation service prior to the end of the Gas Day. ISO-NE, which is strongly advocating an earlier Gas Day start, only speculated that if a de-rate occurred between 3 am and 9 am the “likely cause” was exhaustion of the gas nomination.

However, APGA disagrees with ISO-NE’s causation theory. For the municipal group, “the truth of the matter” is that de-rates due to so-called fuel availability or fuel-related events “occur all day long” in each of the RTO/ISOs, are generally proportional to the period of time examined, and can be attributable to a host of factors. Fuel-related outages and de-rates have many causes and there is no reliable evidence that the start of the Gas Day is a relevant, distinguishing factor that warrants the change in the start, APGA stated.

Factors that cause de-rates could include: insufficient firm pipeline and/or LDC capacity to transport the gas; operational issues on the pipeline and/or the LDC; economic issues related to the price of gas or the price of secondary market capacity at the particular time; and force majeure events at the wellhead, on the pipeline, at a storage facility, on the LDC, and/or at the generator – not the start time of the Gas Day.

APGA suggested that the proposed changes in the NAESB-proposed nomination cycles will help the most to eliminate generators’ morning ramp issues. FERC also is beginning to understand the importance of addressing New England’s over-reliance of gas-fired



generators on non-firm transportation capacity – a problem that will not be cured by any of the measures proposed in the NOPR. The Commission appears to be addressing this, on the other hand, in the AD13-7 and AD14-8 proceedings and related technical conferences, observed the municipal gas group.

With Several Recommendations, State Regulators Offer Support and in Some Cases Caution for FERC’s Proposal Regarding Gas Pipeline Recovery of Modernization Costs; PHMSA Recommends Broad Use of Pipeline Modernization Programs

Offering specific recommendations based on their state’s experience regulating local gas distribution companies (LDCs), a few state utility commissions recently offered cautious approval of FERC’s pending Policy Statement, Cost Recovery Mechanisms for Modernization of Natural Gas Facilities (PL15-1), in filings at the Commission.6 The state regulators -- including the Michigan Public Service Commission (PSC); the North Carolina Utilities Commission (NCUC); Kansas Corporation Commission (KCC); and New York Public Service Commission (NYPSC) – some of which had implemented the kind of mechanisms FERC is considering, suggested strengthening some of the measures to make sure pipelines do not over-recover costs.

For example, Michigan PSC urged FERC to limit the use of a tracker mechanism to recover only capital costs that are “required” by new state or federal regulations to ensure that pipelines are not using the vehicle to recover discretionary expenditures. According to North Carolina regulators, FERC’s five proposed standards may not be adequate

6 FR’s previous coverage of PL15-1 found gas producers,

marketers and end users disagreeing with gas pipelines and gas distributors over whether FERC should allow pipelines to surcharge customers for recovery of natural gas system modernization costs (see FR No. 3035, pp1-14).

enough to protect ratepayers from over-recovery of costs by pipelines. Pipelines should not be provided incentives to make the investments that they already should and do make to fulfill their obligations to provide safe and reliable service. Therefore, as part of a request to obtain a tracker, FERC should require a pipeline to clearly identify for each project the proposed costs to recover via the tracker, and identify the specific new safety or environmental requirement that the project is designed to fulfill.

NCUC also had concerns with the uncertainty of policies that would require interstate pipelines to make upgrades and improvements, leaving unknown the full breadth of compliance costs. “At this time, it is therefore not possible to determine whether existing rate levels or existing regulations and policies are adequate to comply with these additional requirements,” the regulators said. Such an analysis should be completed before the Commission undertakes any change to its current policy against trackers.

Kansas regulators suggested that FERC keep a tight lid on what it considers “eligible costs” for recovery in a tracker mechanism. The expansion of the tracker to include a broader category of costs “is undesirable because a catch-all category would be subject to abuse.” For regulators in New York, one of the main concerns is reducing a pipeline’s return on equity (ROE), if a surcharge is allowed. The NYPSC urged the Commission to consider a pipeline’s incremental reduction in risk due to the proposed surcharge and reduce a pipeline’s ROE accordingly.

From the Federal angle, the Pipeline and Hazardous Materials Safety Administration (PHMSA), the federal agency responsible for enforcing pipeline safety, wants to see FERC consider options to address gas pipeline modernization programs outside of a company-specific rate case.



NOPR. The Commission’s November 20, 2014 proposed Policy Statement on cost recovery mechanisms for modernization of natural gas facilities creates an analytical framework that would allow pipelines to recoup modernization costs necessary for efficient and safe operation of pipeline systems and compliance with new regulations expected soon to be promulgated by the likes of the Pipeline and Hazardous Materials Safety Administration (PHMSA) and Environmental Protection Agency (EPA) and perhaps other agencies.

The Commission proposed to follow five standards that a pipeline would need to satisfy in order to establish a tracker: (1) review of existing rates; (2) eligible costs; (3) avoidance of cost shifting; (4) periodic review of the surcharge; and (5) shipper support. These characteristics are patterned after a recent recently approved contested settlement involving Columbia Gas Transmission, LLC (2013), which included a tracking mechanism to recover substantial pipeline modernization costs.

PHMSA. As the federal agency responsible for overseeing pipeline safety, PHMSA “strongly supports” FERC’s proposed Policy Statement. While an affordable and reliable energy supply is critical to public safety and the nation’s economy, operators may delay pipeline repair and replacement due to cost concerns, at significant risk to public safety and the environment. The majority of pipelines were constructed prior to the establishment of federal pipeline safety regulations: 12% of interstate gas transmission and hazardous liquids pipelines were built prior to 1950. Alone, 59% of gas lines were built before 1970 and 69% were built before 1980.

The Commission’s Policy Statement would provide alternative rate recovery mechanisms for pipeline modernization for companies who seek a rate review, but PHMSA is concerned

that the number of companies actually expected to seek a rate review in the near future “is somewhat limited.” As such, PHMSA encouraged FERC to consider mechanisms that allow for alternative rate recovery without a full rate review. “Also, we further recommend that FERC consider mechanisms that allow operators to seek rate recovery for modernization projects even if the pipeline involved may not be in violation of applicable regulations.”

The agency also encouraged the Commission to work with agencies in states that do not have recovery mechanisms so that they “could take advantage of FERC’s cost recovery model and adopt it at the state level where appropriate.”

Michigan PSC. Michigan’s regulators support the Commission’s efforts to offer a tracking mechanism that would allow recovery of pipeline modernization costs. Claiming first-hand experience in these kinds of matters, the Michigan regulators made several recommendations. The PSC has approved recovery mechanisms for 3 natural gas utilities in Michigan -- SEMCO Energy Gas Co., Consumers Energy Co., and DTE Gas Co. The state sanctioned trackers allow the LDCs to recover costs associated with pipeline safety, such as replacing old and inefficient compressors, leak-prone pipes and performing other necessary infrastructure improvements and upgrades.

The MPSC developed approval of the LDC recovery mechanisms in the context of full general rate cases that evaluated the just and reasonableness of the utilities’ underlying rates. With approval of a tracker mechanism, each LDC is required to file annual reports with PSC discussing the specific capital improvements made during the previous calendar year. This allows for PSC staff to investigate each utility’s compliance with the approved safety mechanism, the regulators explained.



Given its experience, Michigan encouraged FERC to approve the use of recovery mechanisms within the context of a section 4 rate case (pursuant to the Natural Gas Act, NGA), especially in circumstances where the amount of investment in question has more than a de minimus impact on rates. Such a policy would provide an expedited surcharge or tracker mechanism for circumstances where the capital costs do not exceed 10% of the rate base reflected in the pipeline’s existing rates.

In circumstances where capital costs are greater than 10% of the rate base, pipelines should be required to seek such recovery in a full rate filing. FERC then could judge the appropriateness of the expedited surcharge or tracker on a pipeline-by-pipeline basis, with specific consideration given to the size of the capital costs relative to the size of the pipeline’s existing rate base.

Additionally, the Michigan PSC recommended that FERC require each pipeline using the tracker to file an annual reconciliation of the projects completed and costs in the docket approving a surcharge or tracker. “This would provide a trail of the projects and costs for all interested parties, would help ensure that the companies are not including projects or costs that should not be included, and does not violate the limitations of costs to no more than 10% of the rate base,” the PSC said.

Commenting on FERC’s proposal to extend the 5 guiding principles that served as a basis for the Commission’s approval of the Columbia Gas settlement filing to all pipelines via the Policy Statement, the MPSC believes those principles would “serve as a solid foundation,” provided that they are “mandatory conditions and not simply intended to be optional guidelines.”

Additionally, FERC needs to factor in several other considerations “to eliminate ambiguity and to provide for the proper balance of

pipeline and consumer protections,” including the following:

• FERC should limit an expedited surcharge or tracker rate mechanism to mandate that carrying costs associated with the capital costs and any rate base treatment are subject to a section 4 rate filing.

• FERC should not establish a framework for pipelines to accelerate the recovery of contemplated, one-time capital costs, as it may be excessive to provide the pipeline with the ability to accelerate the rate recovery period and to also permit the pipeline to recover depreciation expense plus a return on the unamortized balance of the expenditure. Instead, a pipeline should be permitted to recover a return on its capital investments, which takes into consideration the normal depreciation period and a return on the declining rate base.

• FERC should limit the mechanism to recover only capital costs that are “required” by new state or federal regulations in order to ensure that pipelines are not using the vehicle to recover discretionary expenditures; the Commission’s language in its Policy Statement proposal is too vague in this respect.

• FERC should require that such capital costs in a mechanism be depreciated consistent with the currently applicable depreciation rates for such assets, which would allow pipelines the ability to receive a return on capital investments but also protect ratepayers from a unilateral increase to rate base outside of a pipeline elected section 4 proceeding.

• All amounts approved as part of a safety/modernization surcharge or tracker mechanism must be actually



expended consistent with the intended purpose; or all amounts collected should be refunded, with interest, to ratepayers after a designated period of time.

North Carolina Utilities Commission. The NCUC offered a more cautious view of the Commission’s proposal “to change its long-standing policy against the use of trackers.” While NCUC supports policies that provide pipelines with appropriate incentives to maintain and modernize their facilities, those incentives must be viewed in the context of the NGA’s requirement that rates be just and reasonable.

Until new pipeline safety or modernization requirements are established, it is impossible to estimate “even the relevant universe” of potential additional costs pipelines may need to incur, the regulators said. Absent that data, there is an insufficient basis to support a finding that the existing regulations requiring pipelines to design their rates based on projected units of service is inadequate or results in unjust and unreasonable rates.

In the view of North Carolina’s regulators, FERC’s 5 proposed standards “must be strictly applied” in order to help ensure that ratepayers are not burdened with excessive rates. As drafted, the standards may not be adequate to protect ratepayers from over-recovery of costs by pipelines.

NCUC offered several stipulations to strengthen the proposed standards, including requiring that a pipeline’s base rates be reviewed through a full NGA general rate proceeding or via a collaborative effort between the pipeline and its customers. The latter would be “an essential prerequisite” to a pipeline being allowed a modernization costs tracker. In the event a negotiated resolution is not reached, a full NGA rate case is necessary before a tracker is instituted. Also, eligible costs must be limited to one-time capital costs incurred to meet safety or

environmental regulations, and the pipeline must specifically identify each capital investment to be recovered by the surcharge.

Kansas Regulators. Striking a similar tone, the KCC said it supports a system modernization cost tracker provided that “adequate safeguards” protect against excess rates. “Generally, as long as a tracking mechanism is properly designed, the KCC does not oppose such trackers,” the regulators indicated.

The types of costs appropriate to be included in a surcharge or tracking mechanism are typically limited to expenses or capital expenditures that meet the following characteristics: the costs are (1) outside the control of the utility; (2) are variable and their incurrence is unpredictable; and (3) are likely to cause material financial harm if subjected to the normal ratemaking process. Permitting normal costs to be recovered through a tracker inhibits a pipeline’s incentives to minimize costs and increase service.

To assure that existing rates are just, a pipeline’s base rates must have been recently reviewed, either by means of a general section 4 rate proceeding or through a collaborative effort between the pipeline and customers. KCC opposes the filing of a Cost & Revenue (C&R) study as an alternative to a section 4 determination, given the KCC’s experience litigating pipeline rate cases before the Commission. C&R Studies are inadequate because they do not provide the level of detail contained in a section 4 filing. Also, if parties or the Commission do not believe the pipeline’s rates are just and reasonable based on a C&R Study, the heavy burdens of NGA section 5 are placed on them, rather than on the pipeline.

“The burden should rest on the pipeline to demonstrate that its base rates are just and reasonable, and that process should not envision shifting the burden to those who



disagree with the adequacy of the pipeline’s showing,” the KCC observed.

In lieu of filing a C&R Study, as an alternative, the KCC recommended requiring the justness and reasonableness of the pipeline’s base rates to be based upon a Commission determination made in a general rate case within a relatively short period, not more than three (3) years, prior to the filing of the pipeline’s tracker application.

In addition, the KCC opposes the expansion of “eligible costs” in a tracker to include “other capital costs shown to be necessary for the safe or efficient operation of the pipeline.” The expansion of the tracker to include a broader category of costs is undesirable because the catch-all category would be subject to abuse. Moreover, there is no compelling reason to expand the scope of the limited and focused tracker to include “other” costs, recovery of which is adequately provided for by existing cost recovery mechanisms.

As an exception to general ratemaking practice, the modernization cost tracker should be limited to costs facing interstate pipelines as a result of imposition of new environmental and safety standards over which the pipelines have no real control. Costs that are not shown to be required by PHMSA or EPA regulations should be subject to traditional ratemaking practice.

Moreover, KCC agrees that inclusion of mechanisms to prevent cost shifting “must be an essential element” of any surcharge or tracker mechanism. Here, such mechanisms are likely best developed on a case-by-case basis, tailored to the particulars of the individual pipeline’s tariff and rate structures as well as to the characteristics of the markets served by the pipeline.

In addition, the KCC strongly endorses conditioning pipelines’ access to the proposed modernization cost tracker on a requirement

for periodic true-up of the pipeline’s base rates. FERC has the legal authority to condition pipelines’ continued access to a cost tracker including imposing an enforceable undertaking to periodically refile the pipeline’s base rates. Absent periodic rate review, the very real risk exists that, over time, pipeline rates will depart materially from actual costs by reason of the operation of the modernization cost tracker.

Lastly, the KCC does not oppose extension of the use of accelerated amortization methodologies, calling the idea a “novel concept” that should be explored further.

New York Regulators. The NYPSC wants the Commission to reduce a pipeline’s approved ROE if the proposed cost recovery mechanism is allowed. These regulators argued that the effect of a cost-tracker mechanism on risk was similar to that of Straight Fixed-Variable (SFV) rate design. FERC’s support of SFV rate design, since its adoption in Order 636, has already led to a reduction in risk of pipeline’s under-recovering revenues. By guaranteeing interstate pipelines set revenue recovery, cost-trackers further reduce any risk of under-recovery inherent in rate design based on estimated units of service. Therefore, during pipeline rate cases the Commission should consider the incremental reduction of risk due to the tracker, and the pipeline’s ROE should be reduced accordingly.

FERC’s proposed Policy Statement is based on the Columbia settlement, which it found to be just and reasonable primarily because the settlement, the product of a review of Columbia's base rates, resulted in a base rate reduction and $50 million refund to firm shippers. However, a base rate reduction or refund is not one of the Commission's proposed standards for approving modernization surcharges. In lieu of such a requirement, the Commission should review and reduce a pipeline’s allowed ROE to reflect



risk reduction and ensure that rates are just and reasonable, the NYPSC stated.

In approving the Columbia Gas settlement, FERC found that Columbia Gas would be subject to continuing risk of cost under-recovery, in part because a billing determinant floor was established for calculating the capital cost recovery mechanism. Columbia Gas would impute the revenue that it would achieve by charging the maximum rate for service at the level of the billing determinant floor before truing up any cost under-recoveries. While requiring a billing determinant floor for the surcharge does allow some risk to remain with the pipeline, a tracker mechanism still reduces a pipeline’s risk and transfers it to shippers, the NYPSC warned.

NYPSC also said the Commission should require concurrent base rate review with the establishment of the surcharge. A section 4 rate proceeding or a collaborative effort would be the proper forum for risk analysis and corresponding ROE reduction.

FERC ENFORCEMENT

FERC Majority Brings Enforcement Action Against Canadian-Managed U.S. Power Generator That Allegedly Sought to Collect ISO-New England Reimbursements for Standby Role Based on High Fuel Oil Costs When In Fact Cheaper Natural Gas Was Used and Available

A majority of Commissioners at FERC supported an order to show cause issued on 2/2/15, plus a notice of proposed penalty naming possible violators of its power market manipulation rules as follows: Maxim Power Corp., Maxim Power (USA), Inc., Maxim Power (USA) Holding Co. Inc., Pawtucket Power Holding Co., LLC, Pittsfield Generating Co., LP

(collectively “Maxim”) and Kyle Mitton.7 The Commission’s enforcement staff (IN15-4) apparently found evidence that these entities were parties to a scheme to obtain payments for reliability dispatches based on the price of expensive fuel oil when Maxim in fact burned much less costly natural gas.

Commissioner Tony Clark dissented. Having reviewed the OE Staff Report and Maxim’s responses, he did not find that the record sufficiently supports the Commission moving forward with the order to show cause. Nonetheless, Clark stated, “in the next phase of the proceeding, both FERC Enforcement Staff and the Respondents will have an opportunity to more fully develop the record. As such, I make no prejudgment as to the final disposition.”

The Respondents were asked to show cause why they should not be assessed civil penalties in the following amounts: (1) Maxim and its Named Subsidiaries (jointly and severally): $5,000,000; and (2) Kyle Mitton: $50,000.8 Respondents may also seek a modification of those amounts. The Commission’s order drew 7 Maxim Power Corp. is a Canadian firm based in Calgary,

traded on the Toronto Stock Exchange. Through wholly-owned subsidiaries, it owns power plants in Canada, France, and the U.S. The Canadian parent’s wholly owned U.S. subsidiary, Maxim Power (USA), Inc., itself has several layers of wholly-owned subsidiaries, including the Respondents in this proceeding. Through these subsidiaries, Maxim USA (and its Canadian parent) own and control 3 power plants in New England that sell into ISO-NE.

A January 2013 Memorandum confirmed that (1) in all respects relevant to this investigation, Maxim Power personnel in Calgary (in particular, the company’s Energy Marketing Group) manage and control the Maxim Subsidiaries and (b) none of the Maxim Subsidiaries has any employees. Maxim's Energy Marketing Group has been working in the US Northeast markets since the acquisition of Pawtucket in November 2005.

8 The Enforcement Staff Report concluded: “It is a fair inference that Mitton believed he would personally benefit if he were able to obtain millions of dollars of additional revenue for Maxim by being paid as though Maxim had burned expensive oil when in fact it burned much cheaper gas.” However, among other defenses Mitton had argued that the Federal Power Act does not authorize the Commission to hold individuals liable under the Anti-Manipulation Rule. However, the key staff report points out that the Commission “has long since resolved that issue,” concluding in Order No. 670 that the term “[a]ny entity” in the FPA and the Natural Gas Act is a “deliberately inclusive term” that includes “any person or form of organization . . . .”



on recommendations of OE Staff’s earlier Report. The scheme achieved (until reversed by the ISO’s monitor) $2.99 million in unjust profits, lasted 45 days, and was implemented by personnel with substantial authority in an organization with more than 10 employees. Maxim cooperated with the investigation.

This case presents allegations by OE staff of Respondents’ violation of the Commission’s Prohibition of Energy Market Manipulation, and of Maxim’s alleged violation of section 35.41(b) of the Commission’s rules. These allegations arose out of an investigation conducted by OE staff and are described in the Enforcement Staff Report and Recommendation submitted to the Commission on January 16.

Applying the Penalty Guidelines, the Commission’s staff had requested a penalty of $5,000,000 on Maxim. Because the same conduct violated both the Anti-Manipulation Rule and section 35.41(b) of the regulations, Staff did not recommend a separate penalty for the latter violation. Given Mitton’s central role in the scheme “but taking his financial circumstances into account (Mitton’s annual salary for 2013 was C$120,000 with a $20,000 bonus), staff requested a penalty of $50,000 for his violation of the Anti-Manipulation Rule.

The OE Staff Report alleges that, principally through its employee Kyle Mitton, Maxim engaged in a series of transactions with ISO-New England (ISO-NE) and misleading communications with the ISO-NE Internal Market Monitor (IMM) for the purpose of obtaining “inflated make-whole payments at high fuel oil prices” when a Maxim plant was dispatched for reliability, “even though the plant was actually burning much less expensive natural gas.”9

9 Because the ISO-NE IMM later applied mitigation to recoup

what it viewed as excessive payments to Maxim, the Staff Report does not seek additional disgorgement.

During July and August 2010, Maxim regularly submitted Day Ahead offers to ISO-NE at high oil prices, but on 22 days when it got reliability commitments Maxim allegedly burned much less expensive gas to produce all or almost all of the plant’s energy.

As explained by staff, since Maxim’s plant was being called on to ensure the reliable operation of the grid, “rather than because of economics,” the ISO’s rules provided that Maxim could be paid make-whole payments (called Net Period Commitment Payments) based on its fuel price. The Report alleges that when the IMM asked Maxim about its offers, Maxim (through Mitton) responded with communications giving the impression that Maxim was unable to obtain gas and was therefore burning more expensive oil. Maxim gave those responses to the IMM even though on many days Mitton had bought large quantities of gas before submitting a Day Ahead offer based on oil prices.

Maxim’s advance gas purchases show that it expected the key Pittsfield power plant to be committed for reliability, staff decided. That Maxim was not surprised to get reliability awards is also shown by its own conduct in making advance purchases of gas during the period of this strategy. Moreover, the incorrect impression that Maxim successfully communicated to the IMM is “particularly egregious.”

In its communications with the IMM in July and August 2010, Maxim intentionally conveyed false impressions and omitted material information. Section 35.41(b) of the regulations does not require intent; that is, a market participant can violate the rule simply through lack of due diligence. “Here, however, the violations were deliberate and intentional,” staff charged.

Maxim owns three electric power generators that participate in markets administered by ISO-New England. All 3 of Maxim’s New England plants can burn either gas or oil (are



dual-fuel). The focus of this FERC proceeding is Maxim’s plant in Pittsfield, Massachusetts, which Maxim acquired in 2008. Pittsfield can burn either fuel oil or natural gas to generate electricity, although it typically burns gas, which staff said is almost always much cheaper on a per-MWh basis.

The violations purportedly stemmed from a strategy employed by Maxim and Mitton in the summer of 2010 to collect payments from ISO-NE for reliability dispatches. Maxim executive Kyle Mitton developed and implemented this strategy. The strategy described in this report is one of three identified in a 11/3/14 Notice of Alleged Violations by Maxim and its personnel. Enforcement’s investigation of the other two strategies continues.

According to staff’s report, although the Pittsfield plant is relatively inefficient (and its energy offers are usually above-market rates), the ISO often needs to dispatch Pittsfield for reliability when loads are high. When ISO-NE does so, it ordinarily provides “make-whole” payments to Maxim for the difference between the plant’s offer price and lower market rates.

In July and August 2010 Maxim offered Pittsfield to ISO-NE based on high oil prices. The report said that even though Pittsfield’s offer prices were usually far above market rates and thus did not clear the Day Ahead market based on price, ISO-NE regularly needed Pittsfield “for reliability reasons” during those hot summer months, and committed the plant many times on that basis.

Because it was being committed for reliability, Maxim expected to be, and initially was, paid “an out-of-market payment” based on its offer price – that is, at high oil prices – even though it was actually burning much cheaper natural gas. As a result, Maxim collected extra payments averaging more than $135,000/d on the days it received Day Ahead commitments after offering based on oil prices, and then burned gas.

Apparently when the IMM asked Maxim in mid-July 2010 why it was offering Pittsfield at such high prices, Maxim gave answers that created the false impression that Maxim had to use high-priced oil because the Pittsfield plant itself was having problems obtaining gas.

Maxim actually was not only able to procure gas to satisfy nearly 100% of its commitments, but in many cases had already purchased large quantities of gas for next day delivery when it submitted offers based on oil prices. Enforcement staff determined that these purchases show that Maxim was expecting reliability commitments for the next day, and planned, after offering Pittsfield based on oil prices, to burn gas for much if not all of any commitment period.

Maxim received $2.99 million in excessive payments from this strategy, alleged staff. The ISO later recouped these payments after the IMM discovered (with no help from Maxim) what Maxim had done.

How the RTO System Works. ISO-NE operates both “Day Ahead” and “Real Time” markets for energy. The Day Ahead market operates one day ahead of the date on which the energy is actually delivered (the “operating date”). The Real Time market operates on the day the energy is transmitted, and prices and dispatch levels are resolved on a five-minute basis.

ISO-NE schedules Day Ahead awards (or “unit commitments”) to power plants via (1) marketplace awards, reflecting units committed based on a plant’s economics (or “merit”), that is, because the plant’s offer price is competitive (or “economic”); or (2) resources committed for reliability purposes (i.e., in some cases, a plant is needed to ensure that the ISO-NE grid can run reliably). A plant may clear the Day Ahead market, even if it is very expensive, because of a reliability need. A plant committed because of a reliability need may qualify for Net Commitment Period Compensation (NCPC), commonly known as make-whole payments, depending on the circumstances.



ISO-NE passes through the costs of NCPC payments to load-serving entities, which in turn pass those costs along to households, businesses, nonprofits, and government entities as part of retail electricity bills. Excessive make-whole payments therefore translate into higher electricity bills for consumers.

Like other ISOs and RTOs, ISO-NE has tariff rules designed to prevent generators from unfairly exploiting their market power when they are needed for reliability. In particular, ISO-NE’s rules seek to prevent generators from extracting excessive make-whole (in this case, NCPC) payments when they are dispatched to ensure that the New England grid continues to operate reliably.

The NCPC rules in place during 2010 were the result of an 8/5/09 tariff filing by ISO-NE, which was approved in relevant part by the Commission in October 2009. Under the rules applicable at the time, New England market participants were eligible to receive NCPC payments when a resource is dispatched out of economic merit for reliability purposes and the fuel and variable operating and maintenance (O&M) costs of operating the resource, as reflected in its time-based Supply Offer, exceeded the revenue paid to the market participant in the energy markets.

Specifically, NCPC payments to generators needed for reliability were limited to 110% of the unit’s reference levels. “As Maxim knew, reference levels for oil were, during this period (and almost always) much higher than reference levels for gas. By misleading the IMM about what fuel it burned, Maxim collected millions of dollars in NCPC payments for reliability dispatches at prices based on oil that were far above its actual (gas) costs. Only a later intervention by the IMM protected New England ratepayers from being charged these additional millions of dollars,” the OE staff had concluded in the report conveyed to the full Commission.

NATURAL GAS PROJECTS

Pre-filing Review Begins at FERC for the Atlantic Bridge Project, Joined by Algonquin and Maritimes & Northeast Pipeline

On 1/30/15 Algonquin Gas Transmission, LLC and Maritimes & Northeast Pipeline, LLC (PF15-12) jointly requested approval from Commission staff to initiate the Pre-Filing Review Process for the proposed Atlantic Bridge Project, designed “to deliver critically needed natural gas supplies that will meet immediate and future supply and load growth requirements in the Northeast market area.” The target in-service date for the project is 11/1/2017. The filers anticipate submitting the certificate application in September 2015.

The Atlantic Bridge Project will create additional firm pipeline capacity necessary to deliver 222,000 Dth/d of natural gas to the northeastern U.S., connecting a receipt point on Algonquin’s system at Mahwah in Bergen County, New Jersey with delivery points on the Algonquin’s and Maritimes’ systems. The application explains that the capacity will be created primarily “through take up and relay, looping and additional compression” on the existing Algonquin system, as well as bi-directional flow on the existing Maritimes system.

The applicants held an open season for the Atlantic Bridge Project from 2/2/14 through 3/31/14 and as a result executed precedent agreements with 6 shippers for firm transportation on the facilities. Algonquin held a reverse open season last month, and received no offers to turn back capacity.

The shippers that signed on, including both distribution companies and end users, subscribed to incremental transportation capacity for deliveries in both southern and



northern New England, as well as to specific end use markets in the Canadian Maritime provinces. In addition, Algonquin and Maritimes are negotiating with additional potential shippers that seek capacity for deliveries on or at the end of Maritimes’ system.

The application explains that demand for natural gas has continued to grow in the Northeast as the region seeks “additional access to an economic source of fuel that is domestically produced, clean-burning and efficient.” It is also clarified in the document that “with significant Project shipper volumes designed to flow on both the Algonquin and Maritimes systems, this Project will provide increased pipeline capacity through critical constraint points and satisfies a different purpose from the Algonquin Incremental Market Project.” The AIM Project was designed to meet the needs of southern New England distribution companies for incremental transportation capacity beginning in November 2016.

The Atlantic Bridge Project will consist of approximately 23.9 miles of new mainline pipeline. Construction and installation will involve: (1) 1.2 miles of removal and replacement of 26-inch diameter pipeline with 42-inch pipeline in Rockland County, New York, upstream of Algonquin’s existing

Ramapo Compressor Station; (2) 5.9 miles of removal and replacement of existing pipeline with 42-inch diameter pipeline in Westchester County, New York, downstream of Algonquin’s existing Stony Point Compressor Station; (3) 3.8 miles of removal and replacement of smaller pipeline with 42-inch pipe in Fairfield County, Connecticut, downstream of Algonquin’s existing Southeast Compressor Station; (4) 10.4 miles of 36-inch diameter pipeline loop extension in three Connecticut counties downstream of Algonquin’s existing Cromwell Compressor Station; and (5) 2.6 miles of 36-inch diameter pipeline loop in Windham County, Connecticut, downstream of Algonquin’s existing Chaplin Compressor Station.

The proposal includes a plan to construct approximately 12.3 miles of lateral pipeline, comprised of 2.2 miles of 12-inch diameter pipeline loop on Algonquin’s existing G-2 System in Newport County, Rhode Island; 10.1 miles of 30-inch pipe loop on Algonquin’s existing Q-1 System in Norfolk County, Massachusetts; plus installation of facilities at two existing Algonquin Compressor Stations for an additional 18,615 horsepower (hp).

The project will directly affect approximately 294 landowners or 374 tracts along the pipeline portion.



Tennessee Gas Pipeline Submits FERC Application Seeking Authorization for Broad Run Expansion Project To Deliver Marcellus/Utica Shale Gas Produced by Antero Resources

On January 30 Tennessee Gas Pipeline Co. LLC (CP15-77) submitted to FERC its application seeking authorization to install compression facilities to be located in Kentucky, Tennessee, and West Virginia, and to abandon other facilities, located in Kentucky, referred to as the Broad Run Expansion Project. The proposal is comprised of two components: (1) the Market Component, involving construction, installation, operation and maintenance of compression and related facilities in order to enable Tennessee to provide up to 200,000 Dth/d of firm incremental transportation service “to meet a specified market need”; and (2) the Replacement Component, involving the replacement of older, less efficient compression facilities with new, more efficient facilities at two compressor stations.

In addition to the certificate authority, Tennessee requested that the Commission authorize (pursuant to NGA section 7(b)) the abandonment of certain compression facilities that will be replaced with new facilities as part of the project. “Although these replacements of compressor facilities would not typically require specific abandonment authority,” Tennessee explained it is seeking that authority in this proceeding “since the replacement of these facilities is an integral part of the Project for which Tennessee is seeking certificate authority herein.” Tennessee does not propose to abandon any transportation service as part of the project.

Tennessee asked the Commission for the certificate and abandonment authorizations by 1/31/16, with an eye to complete construction by the 11/1/17 in-service date requested by the key shipper, Antero Resources Corp.

According to the application, this sole shipper executed a binding precedent agreement that provides the market support for the Market Component. The project will deliver natural gas produced in the Utica and Marcellus Shale supply areas to markets in the southeastern U.S.

In order to meet this demand, Tennessee proposes to (1) construct 4 new greenfield compressor stations (two in West Virginia, one in Kentucky and one in Tennessee), and (2) modify 2 existing compressor stations along Tennessee’s system in Kentucky. Each of the new compressor stations is located in close proximity to Tennessee’s existing 100, 500, and 800 Lines.

Besides serving the growing demand for firm transportation to markets in the Southeast, Tennessee said its project will also improve the efficiency and reduce certain emissions by replacing certain less efficient older existing compression facilities with newer, more efficient, cleaner burning, and lower emission compressor units.

Tennessee will provide firm transportation for Antero pursuant to a long-term service agreement under Rate Schedule FT-A of Tennessee’s FERC Gas Tariff and Tennessee’s blanket certificate under Part 284, Subpart G of the regulations.

The estimated cost of the Market Component and Replacement Component, including contingency, overheads, and Allowance for Funds Used During Construction (AFUDC), is approximately $337.9 million and $68.5 million, respectively. Tennessee is proposing an incremental recourse rate under Rate Schedule FT-A for firm transportation on the Market Component facilities.

Since installation of compressor station facilities at existing Compressor Stations 106 and 114 pertain to both the Market Component and the Replacement Component, Tennessee proposes to allocate the cost of



construction at these stations to each project component on a percentage basis. The percentages are based on the horsepower (hp) attributable to the Market Component and to the Replacement Component, as compared to the total hp being installed at each compressor station.

Tennessee held a binding Open Season for the Market Component from 3/25/14 to 4/11/14, offering 200,000 Dth/d expansion capacity from (1) a new point of interconnection, or (2) a mutually agreeable receipt point on Tennessee’s Broad Run Lateral in Zone 3 of its system to one or more mutually agreeable delivery points in Zone 1.

The open season notice also included solicitation for firm transportation service of up 590,000 Dth/d for the “Broad Run System Flexibility Project” to be made available through (1) the use of capacity reserved pursuant to Tennessee’s tariff, and (2) the installation of certain appurtenant facilities and modifications to allow for bidirectional flow of gas on Tennessee.

The construction and installation of appurtenant facilities for the Broad Run System Flexibility Project commenced last July, with the estimated in-service dates of 11/1/15 for Phase I of that project and 11/1/16 for Phase II.

In the open season, Tennessee offered firm expansion capacity for the Market Component at either an incremental maximum recourse rate, to be established through this certificate proceeding, or a negotiated rate, plus fuel and applicable surcharges. Antero, the winning bidder, selected the negotiated rate option. One party, in addition to Antero, submitted a bid during the open season for a portion of the capacity, but Antero was awarded the full 200,000 Dth/d of Market Component capacity.

Actually, before the open season began Tennessee executed a binding Precedent Agreement with Antero for the 200,000 Dth/d

for a 15-year term, reflecting the commercial terms and conditions for its commitment to participate as Original Foundation Shipper. The project shipper has a one-time contractual right to extend the primary term of its firm service agreement at the same negotiated rate that was in effect during the primary term. Any subsequent extensions after the initial extended term would be at the applicable maximum recourse rate for service on the facilities.

The terms of the open season provided that Antero’s agreement would constitute a binding bid. Following the open season and the net present evaluation of the submitted bids, Antero was also awarded all of the capacity in connection with the Broad Run System Flexibility Project. The binding precedent agreement between Antero and Tennessee included the 590,000 Dth/d of capacity for the Broad Run System Flexibility Project.

The firm transportation service for the Broad Run System Flexibility Project and the Broad Run Expansion Project will be provided under separate service agreements, explained the applicant, “as these are separate projects, independent of each other and of whether the other project is placed in service.”

No shippers offered to turn back capacity.

Tennessee proposed an incremental recourse rate under Rate Schedule FT-A for firm transportation service on the Market Component facilities. The incremental recourse rate consists of: (1) a monthly reservation rate of $30.7846/Dth (equivalent to a daily reservation rate of $1.0121/Dth), (2) a daily commodity rate of $0.0000/Dth, (3) applicable demand and commodity surcharges, and (4) applicable fuel and lost and unaccounted-for charges and electric power cost charges.

The incremental recourse rate reflects an incremental cost of service for the Market



Component facilities of approximately $73.9 million, based on (1) the design capacity of those facilities of 200,000 Dth/d; (2) the income tax rates, capital structure, and rate of return approved in Tennessee’s rate settlement in Docket No. RP95-112, et al., and reaffirmed in Tennessee’s (RP11-1566) last rate settlement; and (3) a straight-line depreciation rate of 3.33%, based on an estimated useful life of the Market Component facilities of 30 years.

The currently applicable general system rate for comparable transportation service from Tennessee’s zone 3 to zone 1 is approximately $0.3009/Dth, comprised of a monthly reservation rate of $8.6375/Dth (equivalent to a daily reservation rate of $0.2840/Dth) and a daily commodity rate of $0.0169/Dth.

According to the application, it still is possible that Tennessee will offer interruptible transportation service at those times when the project shipper is not utilizing all of its reserved firm capacity.

Tennessee proposes to roll-in costs related to the Replacement Component facilities into its general system rates in its next section 4 general rate proceeding. This is appropriate, Tennessee believes, because the compressor facilities at two existing compressor stations will be replaced with new and more efficient compressors, “which will allow Tennessee to operate more efficiently and improve system reliability.”

Tennessee also noted that but for the inclusion of the Replacement Component facilities as part of the project it would have had the option to replace these facilities under either section 2.55 of the regulations, or under its blanket certificate authority, and thereby be entitled to rolled-in rate treatment for the Replacement Component facilities.

Constitution Blasts Opponents of Its Certificated Constitution Pipeline and Wright Interconnection Projects; In Context of the Clean Water Act, Is a FERC Pipeline Certificate the Equivalent of a License or Permit?

Constitution Pipeline Co., LLC, recently answered critics and petitions for rehearing of FERC’s certificate order authorizing the Constitution Pipeline and Wright Interconnection Projects proposed by Constitution Pipeline (CP13-499) and Iroquois gas Transmission System LP (CP13-502), respectively. Constitution especially asked the Commission’s permission to respond to the request for rehearing of “Stop the Pipeline" and the petition of the Henry S. Kernan Trust, both of which were submitted on 1/2/15, and the request for rehearing submitted by Earthjustice on December 30.

Constitution Pipeline in particular blasted the claim of the three entities that FERC had violated Section 401 of the Clean Water Act (CWA) by authorizing future facility construction, operation, and abandonment, prior to the issuance of the New York State Department of Environmental Conservation's (NYSDEC) Section 401 water quality certification. This argument, answered the pipeline, fundamentally misinterprets the CWA, the Natural Gas Act (NGA) and the statutory roles and responsibilities of the Commission and the U.S. Army Corps of Engineers in connection with the project.

Plainly, Constitution argues, the order issued by the Commission is neither a license nor a permit and does not authorize activity that could result in a discharge into the navigable waters of the U.S., as Act requires. Section 401 says a state’s water quality certification must precede any federal "license/s” or ''permit[s]," "to conduct any activity . . . which may result in any discharge into the navigable waters."

Rather FERC’s order recognized the public need for the Constitution Pipeline Project and



established that Constitution must obtain all of the necessary federal permits and approvals required to construct the project. Environmental Condition 8 of the order requires Constitution to obtain the CWA permit that triggers the need to obtain a Section 401 water quality certification from New York State—and the wetland permit required by the Army Corps under section 404 of the Act. FERC made clear that the future facility construction and operation must be preceded by a Notice to Proceed from the Commission and that this will not occur until the applicable federal authorizations are obtained or waived, “thus ensuring against discharges to navigable waters” prior to the issuance of the 401 certification and the 404 permit.10

“Movants fail to cite a single case to support the proposition that an order from the Commission granting a certificate … under the Natural Gas Act is a permit or license.” To the contrary, available government publications recognize that a certificate of public convenience and necessity is not a "license" or "permit" under section 401 and that a certificate order may be issued prior to receipt of all federal permits required for construction of an interstate natural gas pipeline.

The order does not authorize construction to begin, which is the only "activity . . . which may result in any discharge into the navigable waters." Instead, the holder of the order must first obtain the applicable permits, submit them to the Commission, and then obtain a Notice to Proceed from the Commission. Without a FERC order in the context of this 124-mile greenfield project, Constitution

10 In order for a section 401 water quality certification to be

required, noted Constitution, the activity causing the discharge must be authorized by a permit or license issued by a federal agency. Federal licenses and permits most frequently subject to this water quality certification include CWA section 402 (NPDES) permits issued by EPA, section 404 (dredge and fill) permits issued by the Corps, FERC hydropower licenses, and Rivers and Harbors Act (RHA) sections 9 and 10 permits issued by the Corps.

would not be guaranteed survey access-- in part due to STP's efforts to discourage landowners from voluntarily providing such access-- and sufficient survey access is a prerequisite for certain federal authorizations required by the Commission before it will issue a Notice to Proceed.

Without the order and/or sufficient survey access, the permitting process would reach an inevitable impasse. The regulatory process is not designed to operate in the facially unworkable manner asserted in the requests for rehearing. “To the contrary, the Natural Gas Act contemplates coordinated federal consideration of infrastructure projects of this nature,” reasons Constitution Pipeline.

Next, Constitution Pipeline responds that no case law or statute supports the “novel” argument that a certificate order under the NGA is a license under the CWA. All pertinent cases cited in the requests for rehearing pertain to the Commission's explicit authority to license hydroelectric projects under the Federal Power Act (FPA). The line of cases pertaining to the Commission's licensing of hydroelectric facilities is inapposite because there is no similar licensing authority for the Commission in the context of interstate natural gas pipelines. Therefore, “the arguments in the requests for rehearing are legally flawed and lacking any applicable legal support.”

Instead, Constitution blasts, these arguments essentially are “nothing more than attempts to frustrate, delay and contort the procedures for obtaining permits required for construction of the Project, which is clearly the objective of an organization named Stop The Pipeline.”

Constitution further says STP's argument that the Commission's issuance of the order violated constitutional due process guarantees fails because STP asserts questionable property interests and because adequate remedies exist that guarantee due process. STP argues only “in conclusory fashion” that



the order's issuance was premature and violated due process guarantees.

STP fails to present and apply the appropriate standard used to analyze due process claims. United States Supreme Court precedent commands that in order to establish a due process violation, a petitioner must show: (1) a cognizable liberty or property interest; (2) the deprivation of that interest through state action; and (3) that the procedures employed are constitutionally inadequate.

STP, though, asserts generally that it advocates for the due process rights of affected landowners and all of its members, “but then conflates the grievances of both groups.”

First, a general interest in nature or the environment is not a protected liberty or property interest in the due process context. STP implies that its members have a protected due process interest in the "water, wildlife, and aquatic species that belong to the citizens of New York State." The legal support for the recognition of this interest is nowhere to be found, Constitution parried.

The only “cognizable” property interest STP may assert is the interest of its members who also are landowners subject to condemnation proceedings. Aside from this subset whose real property interests are directly implicated by the pipeline's construction, STP fails to show the existence of a protected property interest.

Second, nor does the issuance of the certificate itself affect any property interests of affected landowners. A holder of a certificate may only acquire property "by the exercise of the right of eminent domain in the district court of the United States.” There would not be any deprivation of the property interest until after the conclusion of a legal proceeding, as guaranteed by the NGA. Because the required deprivation has not yet occurred, STP's landowner constituency has not suffered the

requisite injury necessary to trigger full due process protections.

Constitution Pipeline argues, third, that there are in fact constitutionally adequate procedures in this case. STP has not met its burden to show otherwise. The final step of the due process inquiry-- determining exactly what process is due-- involves analyzing whether persons being deprived of protected property interests have received constitutionally adequate procedures. A constitutionally adequate procedure is one that provides notice and an "opportunity to be heard at a meaningful time and in a meaningful manner.”

To determine the adequacy of a set of procedures, the Supreme Court instructs that the following factors must be balanced: (1) the private interest involved, (2) the risk of an erroneous deprivation of that interest through the procedures utilized, as well as the probable value of additional procedural safeguards, and (3) the government's interest, including the burden that additional procedural requirements would impose.

In that context, reasons Constitution Pipeline, the private interest involved here is minimal, there is very little risk of erroneous deprivation, and the government's interest is strong. Together, these factors demonstrate that the available procedures-- the Commission's initial pre-issuance review, its review on rehearing, and the availability of federal court review-- are constitutionally adequate.

For the landowners, the private interest is unencumbered property, and for the public more broadly it is the undisturbed habitat of various types of wildlife. The latter interest is of little relevance in the due process context, and the landowners' property interests should not weigh heavily in the analysis. Rather, Federal courts have stated that interests involving one's economic livelihood have the highest importance.



The Commission is equipped to conduct a thorough analysis before issuing an order and STP has the availability of federal court review of the order. This structure of administrative and judicial review guarantees that any deprivation will not occur without extensive deliberation. As to the affected landowners, the availability of eminent domain proceedings ensures that they will not be deprived of their property without due process.

And the government's interest in the issuance of the order and the commencement of the project is strong, as noted in various federal cases explaining that a strong public interest exists in constructing and operating interstate pipelines. Unnecessary process would delay the construction schedule and frustrate the government prerogatives underlying the project.

Instead of employing the foregoing analysis, Constitution Pipeline sums up, STP incorrectly claims in a conclusory fashion that it is "fundamental that the opportunity to be heard must happen before a citizen is deprived of a property interest."

Constitution Pipeline points out that STP does not specify whether it asserts that the Commission's issuance of the order violated “procedural” due process or “substantive” due process. Although the foregoing analysis focused on procedural due process, to the extent that STP advances a substantive due process claim, that claim also fails. Substantive due process claims are reserved for rare situations that "shock the contemporary conscience," and require petitioners to demonstrate "an act or grave unfairness, such as a deliberate flouting of the law." FERC’s action does not meet such a high standard.

Finally, Constitution Pipeline argues that the Commission's analysis satisfied its duties under the National Environmental Policy Act (NEPA). Earthjustice's argument that the

Commission was required to consider the consequences of "induced" gas production and transportation infrastructure is unavailing. The Commission did analyze "the general development of the Marcellus Shale in proximity to the projects." Even if it hadn’t, Earthjustice's argument depends on the unsupported supposition that the project will induce natural gas development.

Earthjustice erroneously argues that the analysis of cumulative impacts in the final EIS falls short of what NEPA requires and claims that the Commission failed to provide sufficiently detailed data to support its conclusions. In reality, answers the pipeline, the Commission provided ample factual support for each of its conclusions and explained why the cumulative impacts would be minor or minimized below a significant level. The final EIS explains that by implementing staff s recommended mitigation measures for the proposed projects, in combination with measures proposed or required by state and local agencies with overlapping or complementary jurisdiction, the cumulative impacts would be minimized below a significant level.

Contrary to STP’s claim, continues Constitution Pipeline, FERC did appropriately consider Tennessee's Northeast Energy Direct Project and Iroquois' South-to-North Project in its analysis of this project. The Commission was not obligated to consider these other projects at all. An agency need only consider "projects" in its NEPA analysis that are "proposals in which action is imminent."

Also, the Commission did not improperly segment the Northeast Energy Direct and South-to-North Projects from its review.

And the assertion that Constitution Pipeline has nowhere to deliver its gas without the Northeast Energy Direct and South-to-North Projects overlooks critically important components of the overall new project and is squarely contradicted by the record, argues



the pipeline. As a result of the Wright Interconnection component and the Capacity Lease Agreement, the gas transported through Constitution will be available for delivery into the existing Tennessee and Iroquois systems. The Constitution Pipeline will provide access to inexpensive, clean-burning natural gas from Pennsylvania. Shippers with subscribed capacity on these lines currently relying upon more expensive sources of gas from Canada and elsewhere will be able to replace those existing supplies with cheaper gas from Pennsylvania.

For the same reasons, Constitution Pipeline maintains that STP's arguments that the project lacks substantial independent utility or need also should be rejected.

Peoples LDCs Object to Proposal of Equitrans to Establish a Zone to Manage Services on Proposed Ohio Valley Connector

A joint protest lodged with FERC on January 28 by Peoples Natural Gas Co. LLC, Peoples TWP LLC, and Peoples Gas WV LLC11 contested the proposed rate treatment of the expansion project – known as the Ohio Valley Connector Project -- proposed in the underlying application of Equitrans, LP (CP15-41) filed at the Commission on 12/19/14. Equitrans is seeking Commission authorization to construct certain pipeline and compression facilities located in West Virginia and Ohio that will allow Equitrans to provide up to 850,000 Dth/d of additional firm transportation.

11 In December 22013 Equitable Gas Co., LLC merged with

and into Peoples with Peoples being the surviving entity. Equitable Gas Co., through its Pennsylvania and West Virginia divisions, gathers, processes, stores and distributes natural gas at retail in the Commonwealth of Pennsylvania and the State of West Virginia. It served approximately 270,000 residential, commercial and industrial customers in western Pennsylvania and approximately 13,000 customers in north-central West Virginia. Pennsylvania customers are now served by Peoples and West Virginia customers are now served by Peoples WV.

These LDCs fully support Equitrans’ proposed expansion but they maintain that the rate treatment of the project should be revised. They said the Commission should reject Equitrans’ request for a new rate zone for this project and instead authorize Equitrans to implement an incremental rate for the proposed service.

Except for its Allegheny Valley Connector system, Equitrans operates a reticulated system with postage stamp rates. But Equitrans is proposing to create a separate rate zone for this project. The pipeline claims in the application the separate zone will serve to protect existing customers from subsidizing costs of the asset.

According to Equitrans, the Year 1 rate base associated with the Ohio Valley Connector Project is $396 million compared to Equitrans’ Mainline and Sunrise existing rate base of approximately $854 million. The overall plan ensures that Equitrans, not its existing customers, is at risk if the project’s shippers do not re-contract for capacity at the expiration of their service agreements, or if it does not generate enough revenue to cover the annual cost of service. Also, the separate zone concept ensures that only those customers that use the project will pay for the facilities. Additionally, because the project facilities enable shippers to access markets which are currently not accessible from Equitrans’ Mainline and Sunrise Systems, establishing the new rate zone for the Ohio Valley Connector for shippers desiring to use these proposed new delivery points is appropriate.

According to Peoples, the factual assertions, even if true, do not support the establishment of a new rate zone on the Equitrans’ system. Rather, they support the establishment of an incremental rate for service from these proposed facilities.

Peoples noted that the incremental treatment is used by Dominion Transmission, Inc.



(CP14-555), another pipeline in the Equitrans market area with postage stamp rates, to price services related to a similar east-to-west pipeline extension. It is also the customary method employed by other pipelines to fix rates for expansion projects where the incremental rate exceeds the current system recourse rate, in accord with the Commission’s Certificate Policy Statement.

The Peoples LDCs stressed that this is not the first time they expressed concern with regard to “what appears to be an attempted de facto conversion by Equitrans to zone rates.”12 If Equitrans desires to convert its postage stamp rate design to a zone rate design, it should do so in a section 4 rate filing. Then Equitrans would have the burden of proof to support the reasonableness of a change from its long established postage stamp rate design.

The appropriateness of zone rates on the Equitrans system “is certainly questionable in that zone rates are generally a form of distance-based rates where costs can be shown to vary with the distance of the gas transportation,” stated Peoples LDCs. In this case, especially, distance of transportation does not appear to be a factor. Moreover, the proposed facilities are connected to and integrated with Equitrans’ existing system.

12 Equitrans (RP14-817, 2014).

NATURAL GAS PIPELINE TARIFFS

No FERC Policy Requires ANR Pipeline to Give Original Natural Gas Shipper a Right to Match in Open Season Bidding for Capacity Requested by that Shipper; Commission Addresses Matching Right of Shippers Holding Longer Term Pre-Arranged Deals

A FERC letter order issued January 29 dismissed concerns raised by Integrys Gas Group and affirmed that to the extent ANR Pipeline Co. (RP15-274) initiates an open season in response to a shipper request for service commencing within 6 months there is no Commission policy that requires the pipeline to give the original requesting shipper the right to match the highest bid submitted in the open season. Because the parties that “value the capacity most” will submit the highest valued bids in the open season, the order affirmed that ANR’s proposal is consistent with the existing policy awarding capacity to the party that values it the most. The Commission assumes that the pipeline will act in its own economic interest and seek the highest possible rate from non-affiliated shippers. (Tennessee Gas Pipeline Co., 2011).

The Commission also affirmed that ANR had sufficiently supported its different treatment of pre-arranged deals. Pre-arranged deals, reasoned the agency, often relate to complex projects involving extensive planning processes before requesting pipeline service, and not allowing the pre-arranged deal shipper to retain its requested capacity by matching the highest bid could impede project development. Given that the pre-arranged deal shippers are not similarly situated to those seeking more immediate service, ANR’s proposal to give pre-arranged



shippers a bid-matching opportunity is appropriate.

The Integrys protest followed on a tariff change filing made in December by ANR. FERC has now accepted the proposal, effective February 1, subject to conditions.

Among other things the pipeline’s filing provides that if a party submits a valid request for long-term capacity, ANR may either grant the request or hold an open season for the capacity. If ANR decides to conduct an open season, the initial service request will be included as a bid in the open season. The original requesting party may submit a bid with greater economic value during the open season, but once the open season has concluded, the original requesting party will not be permitted to obtain the capacity by matching the highest bid.

A separate provision in ANR’s tariff addresses prearranged sales for 6 months or more in advance of the service commencement date. The sale of such capacity is subject to an open season in which other parties may bid on the capacity. Unlike capacity sales for more “immediate” service, the prearranged shipper is given the opportunity to retain the capacity by matching the highest bid submitted in the open season.

ANR also had proposed to modify its general tariff terms to reduce the time period within which a shipper must execute and return a tendered service agreement from 30 days to 15 days. This proposed modification is intended to ensure expeditious completion of capacity sales. After some reconsideration, this proposal will be readjusted.

ANR’s proposal, in addition some other housekeeping matters, also (1) clarified that FDD service of at least 12 consecutive months must end on March 31 of each year; (2) broadened ANR’s and a shipper’s ability to negotiate contract extensions; (3) simplified

procedures related to prior-period adjustments; (4) clarified the right-of-first-refusal provisions related to the sales of interim capacity; and (5) modified the service request form so a shipper may specify whether it will accept less than the requested maximum daily quantity (MDQ) if the full amount of the requested capacity is unavailable.

Integrys filed a protest and the Wisconsin Distributor Group (WDG) filed adverse comments on 1/5/15. Integrys argued that it is inconsistent for ANR to allow a prearranged shipper to match any bid submitted during an open season while not also allowing shippers requesting more immediate service the option to match the highest bid. Integrys essentially argued that differences between prearranged-deal shippers and other shippers does not warrant different rights.

WDG had asserted that gas distribution utilities in the State of Wisconsin would face difficulties satisfying the proposed 15-day requirement to return a tendered service agreement. Specifically, due to the 21-business day review period for service changes imposed by the Wisconsin Public Service Commission, Wisconsin utilities may be unable to satisfy the 15-day deadline.

ANR acknowledged WDG’s concern and suggested a tariff amendment to address the possibility of state-imposed actions that could warrant a different deadline (up to 30 days). FERC conditioned this letter order authorization to permit ANR to resubmit its tariff with the fix that the pipeline had suggested.



FERC Accepts a Rate Schedule IBS (Interruptible Balancing Service) Proposed by Equitrans, Subject to Clarification Sought by Peoples’ LDCs

On January 30 FERC accepted Equitrans, LP’s (RP15-301) pro forma tariff records filed in late December to establish a new interruptible balancing service under Rate Schedule IBS. Based on its review of Equitrans’ filing and its answer to comments of Peoples local distribution company customers, the Commission found proposed Rate Schedule IBS to be just and reasonable, subject to Equitrans filing to clarify the “imbalances” to which Rate Schedule IBS will apply as agreed in its answer to Peoples. Equitrans should file actual tariff records in compliance with the regulations, and consistent with the pro forma tariff records approved, when it files to implement Rate Schedule IBS.

According to Equitrans, the balancing service will allow over or under-tendered balances created under a transportation service agreement to be transferred to the balancing service. The proposed service purportedly will give customers additional flexibility to manage their receipt point imbalances on Equitrans’ system. Equitrans states that upon nomination by a customer it will receive or deliver a quantity of gas to balance the customer’s account.

Equitrans proposes to use its currently effective rates for Rate Schedule Lending and Parking Service (LPS) as the applicable rates for IBS service. Unlike its existing LPS service, IBS service is directly linked to transportation provided under Rate Schedules Firm Transportation Service (FTS), No-Notice Firm Transportation Service (NOFT), Firm Transportation Storage Service (FTSS), Interruptible Transportation Service (ITS) and Transportation Service (STS-1). Additionally, Rate Schedule IBS would permit customers to both park and receive loaned quantities of gas

rather than being limited to one or the other. Equitrans proposes to include the right to agree to a discount that is between the maximum and minimum base tariff rate. In addition, Equitrans may agree to a negotiated rate for IBS service.

There will be no reallocation of costs to this new service. Equitrans expects that prior customer imbalance activity may not be indicative of future behavior and therefore the costs and revenues associated with the new service are unknown and based upon future subscription to the service. Accordingly, Equitrans requested and was granted by the Commission a waiver of the requirement in the regulations to provide a projection of the estimated effect on revenue and costs over the twelve-month period commencing on the proposed effective date of this filing.

Peoples Natural Gas Co. LLC, Peoples TWP LLC and Peoples Gas WV LLC (collectively, Peoples) filed a motion to intervene and comments. Peoples expressed support for the IBS service but sought an explanation of the differences in its proposed service from its service under Rate Schedule LPS, and the similarities of the proposed IBS service to the services of other pipelines relied on by Equitrans in support of its filing.

In response to Peoples’ inquiry, Equitrans explained that the IBS service is linked directly to transportation service provided under Rate Schedules FTS, NOFT, FTSS, ITS, or STS-1, while Rate Schedule LPS does not require transportation service in order to effectuate a park or loan. Additionally, an IBS customer may both park and receive loaned quantities of gas, while a LPS customer is restricted to either a park or a loan for the term of the Service Agreement.

Equitrans noted that similar balancing services instituted by Columbia Gas and Dominion Transmission are interruptible services designed to assist customers in the



management of daily and monthly imbalances as is Rate Schedule IBS.

By way of clarification, Equitrans also explained for Peoples’ sake that an IBS customer who is a receipt point operator is not required to have a transportation service agreement. Equitrans notes, however, that in order to transport such volumes across Equitrans’ transmission system, there must be a transportation service agreement either by the same customer or by a separate customer to transport volumes on their behalf.

Peoples also requested that Equitrans clarify what “imbalances” can be addressed under Rate Schedule IBS. Equitrans proposed to clarify that Rate Schedule IBS will assist customers in managing both imbalances and scheduling variances. Equitrans asserted that its clarification is consistent with the use of “imbalances” in its tariff. Equitrans proposes to submit this language in a compliance filing at the time it proposes to implement the proposed service. FERC accepted the proposal.

Widely Protested Tariff Changes, Including New Imbalance and Flow Management Service and Penalties, Sought by MoGas Pipeline Are Set By FERC for Technical Conference

A FERC suspension order issued 1/3/15 established a technical conference to allow protesters and parties the opportunity to examine more carefully a December 22 tariff filed by MoGas Pipeline LLC (RP15-276) that would (1) implement a new short-term imbalance management service (SBS); (2) make a clarification to its authority to issue operational flow orders (OFOs); (3) address the circumstances that may cause it to utilize flow control; and (4) create a daily unauthorized overrun charge, a daily scheduling penalty, and a penalty on month-end imbalances. MoGas maintains that the Commission has approved similar provisions

for other pipelines and that these proposed changes will allow it to continue to provide consistent, reliable service and to compete for additional load. The proposal is suspended to become effective July 1, subject to refund and conditions and further order of the Commission.

Laclede Gas Co. filed a protest, request for technical conference, and a request for maximum suspension of the tariff filing. Laclede Energy Resources, Inc. filed a request for a technical conference, but did not challenge specific aspects of the MoGas filing. Union Electric Co. d/b/a Ameren Missouri filed a conditional protest and a request for technical conference, and possibly an evidentiary hearing. Municipal Intervenors filed a protest, request for issuance of a deficiency letter, request for technical conference, request for maximum suspension, request for refund effective date, and a request for hearing. The Missouri Public Service Commission (MoPSC) filed a protest and request for a technical conference with a five-month suspension and, in the alternative, a hearing.

Several parties complained that MoGas had given no advance notice of these changes and that the timing of the proposed changes during the winter heating season creates problems for customers because adjustments to gas supply could be required. The protesting parties also contended that the changes have not been shown to be just and reasonable and allow MoGas too much discretion.

According to MoGas, the SBS will be provided from linepack; capacity available for the SBS would be posted each day. Shippers electing this service will have their daily imbalances automatically nominated into their SBS accounts to the extent that MoGas has the operational ability to provide the service. Shippers will pay a daily charge on their SBS account balances, but will not be subject to



penalty provisions. However, when the pipeline cannot provide the SBS due to operational circumstances, it will notify shippers in advance, and the regular penalty provisions will apply to scheduling deviations, unauthorized overruns, and imbalances.

Additionally, MoGas states that the SBS will be subject to daily and cumulative caps, which will be posted on the company’s informational postings site and stated as a percentage of maximum daily quantity (MDQ). When a shipper reaches the cap, the regular penalty provisions will apply to scheduling deviations, unauthorized overruns, and imbalances incurred until the SBS account balance is reduced below the cap.

MoGas states that the rate for the SBS will be equal to the maximum stated tariff IT (interruptible) rate, although to encourage shippers to use the service it may offer discounted rates.

Also, MoGas henceforth intends to issue OFOs when necessary to preserve the integrity of its system. The tariff clarifies the circumstances that may cause MoGas to implement flow control, defines the scope of OFOs on its system, and the steps it will take before issuing an OFO.

Under the current tariff, MoGas may adjust or limit shipper deliveries in certain situations. MoGas has flow control capability installed at all but the smallest of its existing delivery points and it is able to control the delivery of gas off of the system at such points as necessary. Deliveries at certain larger points on the system are regulated using the pipeline’s flow control capabilities, while deliveries at smaller points are regulated by pressure control without using the pipeline’s flow control.

MoGas asserts that its system runs effectively and efficiently under these operating conditions and that the proposed tariff

changes are not intended to change the status quo. Rather, the proposed changes seek to clarify circumstances that may cause it to employ its existing flow control capability at points that currently are operating under pressure control. Specifically, the new language says it may install and/or operate remote or manual flow control equipment when it determines that such equipment will contribute to the safe, reliable, efficient, and orderly operation of its facilities.

MoGas states that the proposed tariff changes also include the addition of a daily scheduling penalty for situations in which a shipper takes delivery of more or less gas than its Scheduled Quantity when such delivery is below the shipper’s MDQ. However, shippers that receive the majority of their gas on a given day at delivery points that operate pursuant to the pipeline’s flow control equipment will not be assessed daily scheduling penalties because the majority of their deliveries are controlled by the pipeline.

Different daily scheduling penalties, with certain exceptions, would be assessed during non-critical periods and critical periods. MoGas explains that shippers will incur scheduling penalties when they take quantities that vary from the scheduled quantity by the greater of 50 Dth or 3% of their MDQs.

During non-critical periods, shippers will be subject to scheduling penalties equal to MoGas’s IT rate for each Dth exceeding the greater of 50 Dth or 3% of the volumes scheduled by MoGas. During critical periods, shippers will be subject to scheduling penalties equal to the greater of $25 or three times the Chicago Hub index price published in NGI’s Daily Gas Index for each Dth exceeding the greater of 50 Dth or 3% of the volumes scheduled by MoGas. MoGas maintains that scheduling penalties during critical periods must be high enough to act as an effective deterrent to harmful conduct.



The proposed daily unauthorized overrun penalty is designed to prevent a different type of behavior than the behavior addressed by a scheduling penalty.

MoGas explains that the daily delivery point scheduling penalty applies to shippers that take quantities of natural gas below their MDQs, but are not taking a quantity of gas consistent with their Scheduled Quantities. In contrast, the overrun penalty applies when shippers take gas in excess of their MDQs without obtaining authorized overrun service. MoGas contends that this conduct significantly increases the risk to the safe and reliable operation of the system and its ability to meet its firm service obligations. According to the pipeline, the rate appropriately takes into account the lessened impact unauthorized overruns will have on the system during non-critical times.

MoGas has adopted a monthly imbalance penalty as well. It intends to charge twice its IT (interruptible transportation) rate on any imbalance that exists at the end of the month and is not resolved in the 17 business days of the following month, when shippers may net and trade imbalances. MoGas contends that managing imbalances on a monthly basis reduces the administrative burden on a small company such as MoGas and also provides shippers greater flexibility within a month to manage and minimize net imbalances. MoGas will credit to non-offending shippers the imbalance penalty revenues, net of costs, in accordance with Order No. 637. MoGas cites Commission precedent that permits pipelines to charge monthly imbalance penalties so long as the pipelines offer imbalance management service (i.e., park and loan) to the extent practicable, thereby allowing shippers to minimize the possibility of incurring imbalances.

The Commission found that it is not possible to determine from the pleadings whether MoGas’s proposed tariff changes are just and reasonable.

OIL PIPELINE PROJECTS

FERC Determines in Favor of Enbridge Energy’s Scheme to Recover Costs of Its Four-Part Midwestern Project 24, Despite Reservations Aired by Suncor Marketing and Flint Hills Resources

By letter order issued on February 2, FERC accepted a filing made on December 1 by Enbridge Energy, LP (OR15-4) which comprised a Supplement to the Facilities Surcharge Settlement13 to permit it to recover the costs of its Project 24, which includes four components: (1) the Line 61 Expansion (will expand Line 61, also known as the Southern Access Line, between Superior, Wisconsin, and Flanagan, Illinois, and includes new tankage at the Superior and Flanagan terminals; (2) the Line 67 Expansion; (3) the Line 62 Twin; and (4) the Line 6B Expansion. Support came from the Canadian Association of Petroleum Producers (CAPP). The Commission accepted the Supplement, finding that CAPP’s comments and Enbridge Energy’s reply to the issues raised by protester Suncor Energy Marketing Inc. ands Flint Hills Resources Canada, LP sufficiently address the issues raised by those two parties. The Commission’s approval does not constitute pre-approval of any costs associated with Project 24, which can be contested when Enbridge Energy files rates that include those costs. For these reasons, the Commission approved the Supplement to Settlement on the grounds that it appears fair, reasonable, and in the public interest.

13 The settlement was approved by FERC in 2004. The

Facilities Surcharge was a component of Enbridge’s U.S. tariff rates, allowing the recovery of costs associated with shipper-requested projects through an incremental surcharge added to the existing base rates. The Facilities Surcharge Settlement is intended to be a transparent, cost-of-service-based tariff mechanism that will permit a true-up each year to actual costs and throughput. The surcharge is not subject to indexing. According to Enbridge, since 2004, FERC approved 23 projects for inclusion in the Facilities Surcharge, most recently on 7/31/14, in Docket No. OR14-33.



With this approval in hand, Enbridge’s project can be reflected in a separate rate filing that Enbridge said it expects to submit on or around February 27, to be effective 4/1/15.

The Line 61 Expansion will consist of two phases, the first of which will increase the capacity of the segment to approximately 800,000 bpd beginning approximately during the first quarter of 2015. The second phase will increase capacity to the full capacity, and those facilities are expected to enter service in the third quarter of 2015. Enbridge Energy estimates that the capital cost for this project will be $1.52 billion.

Enbridge Energy determines the projects to be included in the Facilities Surcharge through a negotiating process with CAPP. In this case, Enbridge proposes to add Project 24 to the Surcharge to recover the costs of the Project 24 facilities that it expects to place in service in the near future. Three of the four components are expected to be in service in 2015. Although the estimated in-service date of one of Project 24’s components, the Line 6B Expansion, is some time during the first quarter of 2016, Enbridge Energy clarifies that the costs of the Line 6B Expansion will only be included in its 2015 tariff filing if that component goes into service in 2015.

Enbridge Energy emphasizes that the surcharge components for Project 24 will be based on annual revenue requirement calculations using factors agreed to through the Facilities Surcharge Settlement. Further, the surcharge will be trued-up annually to actual costs and throughputs.

Enbridge estimates that this project will increase the total capacity of Line 61 from 560,000 barrels per day (bpd) to approximately 1,200,000 bpd. Project 24 will expand constrained portions of the Lakehead System, which is the U.S. portion of the Enbridge Mainline that transports crude oil and natural gas liquids from Western Canada to the U.S. upper Midwest and on to Eastern

Canada and New York State. According to Enbridge Energy, the expanded capacity will help accommodate incremental crude oil production from the Bakken Region of Montana and North Dakota, as well as increased production from the oil fields in Western Canada.

Enbridge Energy originally agreed with CAPP that the Line 61 Expansion pipeline would have a 30-inch diameter, and the Commission approved the proposal on those terms in 2006. However, following further negotiations with CAPP, it modified the pipeline’s design. Subsequent developments, including particularly an increase in the forecasts for Western Canadian oil sands production in future years, led to the conclusion that a 30-inch pipe would not be the most efficient size. Initially, the settling parties discussed an increase to a 36-inch pipe but Enbridge Energy finally proposed construction of a 42-inch diameter pipeline with an initial capacity of 400,000 bpd (consistent with the original Offer of Settlement), but with a potential maximum capacity of up to 1.2 bpd.

As part of that update, Enbridge Energy agreed with CAPP that it would exclude 12.2% of the capital costs of building Line 61 from the Facilities Surcharge calculation at that time, which reflected the incremental cost of building a 42-inch pipeline rather than a 36-inch pipeline. In other words, Enbridge explained to FERC that it was upsizing the project to a 42-inch diameter line at its own risk. But the large diameter pipe would provide the capacity to relieve bottlenecks and avoid apportionment of scarce capacity through the addition of relatively inexpensive pumping power rather than by the installation of new pipe parallel to the existing route.

Enbridge Energy emphasizes that the change to a larger line will allow it to increase the capacity of Line 62 to the full 1,200,000 bpd at a much lower cost than would be incurred to build a new line. Moreover, because the



additional capacity will now be utilized, the estimated capital cost for the current project includes $268 million agreed to by the parties as the cost of the 42-inch upsizing (i.e., the equivalent of the 12.2% earlier excluded from the Facilities Surcharge).

The Line 67 Expansion will expand the Alberta Clipper line between Clearbrook, Minnesota, and Superior, Wisconsin, growing the capacity of the segment from 570,000 bpd to approximately 800,000 bpd. Enbridge Energy expects that the expanded line will enter service in mid-2015, with a total capital cost of $200 million.

The Line 62 Twin portion of Project 24 involves the construction of a new 36-inch diameter pipeline that will parallel Enbridge Energy’s existing Line 62 segment between Flanagan, Illinois, and Hartsdale, Indiana, as well the addition of a new pump station. The new line will initially handle approximately 570,000 bpd, and it is expected to be in service during the third quarter of 2015. Its total estimated capital cost is $500 million.

Finally, the last component, the Line 6B Expansion, will enhance that segment’s facilities between Griffith, Indiana, and Stockbridge, Michigan. In fact, according to Enbridge Energy, this segment of Line 6B was replaced recently, and the replacement pipe will not be expanded further. Instead, there will be pump station modifications and new tankage at the Hartsdale and Stockbridge terminals, which will increase the total capacity of Line 6B from 500,000 bpd to approximately 570,000 bpd. Enbridge Energy expects the Line 6B expansion to commence service during the first quarter of 2016 or earlier, at a cost of $365 million.

Protest. Suncor protested and Flint Hills Resources Canada filed a request for clarification or, in the alternative, a protest. CAPP filed a motion to intervene in support of the Supplement to Settlement. Enbridge

Energy filed a reply to Flint Hills’ request for clarification and Suncor’s protest.

Among other things, Suncor had asked the Commission to defer action on the Supplement to Settlement until after Enbridge Energy has filed a tariff to incorporate the costs of Project 24 into its rates.

Suncor argued that the Enbridge Energy proposals to include costs related to the construction of 12 tanks as part of the Line 6B Expansion and Line 61 Expansion and the expansion of Line 61 from 800,000 to 1,200,000 bpd are inconsistent with agreements between Enbridge Energy and its shippers. Suncor complained that the Supplement essentially does not meet the Commission’s requirement that carriers must justify their proposals at the time of their initial filings rather than waiting until after protests are filed.

Moreover, it appears to Suncor that some of the proposed new tanks will not be break-out tanks for transportation on the Mainline, but rather may be receipt or delivery tanks serving other Enbridge pipelines; the full expansion of Line 61 will not be used and useful; and the Supplement fails to provide any justification for the second incremental increase of 400,000 bpd on Line 61.

Flint Hills shares Suncor’s concern that Enbridge Energy is expanding the capacity of its Mainline from points downstream of Superior to 1,200,000 bpd before it expands Mainline capacity upstream of Superior by a corresponding increment of capacity, or by synchronizing the Mainline expansion downstream of Superior with construction of the Sandpiper Project that is already approved to transport crude oil from North Dakota and Montana to Clearbrook and Superior.

Flint Hills also had sought clarification that the costs of storage tanks included in the Facilities Surcharge are related exclusively to performing a break-out function, rather than a receipt or delivery function.



In support of the Supplement to Settlement, first, stated CAPP, the Facilities Surcharge Settlement process demonstrates the need for a clear statement of agreed-upon principles relating to the allocation of tankage costs to Mainline services versus allocation to other services, where tankage facilities may serve multiple purposes. According to CAPP, when these underlying principles are resolved, they will be applied in determining the specific costs to be included in Enbridge Energy’s tariff rates. In agreeing to the Supplement to Settlement at issue in this proceeding, CAPP anticipated this result.

Additionally, CAPP argued that concerns about the potential imbalances in upstream and downstream facilities should not preclude the Commission’s approval.

In its reply, Enbridge Energy addresses the issues raised by Suncor and Flint Hills, contending that those issues should not prevent the Commission from approving the Supplement. Enbridge Energy emphasizes that these two parties do not oppose recovery of the Project 24 costs, nor do they challenge most components of Project 24. Enbridge Energy also insists that nothing in the Supplement is intended to deprive any potentially affected party of its ability to challenge tankage costs at the time those costs are actually included in tariff rates.

Enbridge Energy affirms that Commission approval of the Supplement should not prejudice the rights of any party or result in any recovery of inappropriate costs through the Settlement. Additionally, continues Enbridge Energy, if the tankage principles are not resolved prior to the time that some of the Project 24 tanks enter service, any discrepancy will be resolved by the annual true-up of the Settlement.

Enbridge Energy next emphasizes that the Supplement to Settlement does not require a date certain for completion of the second phase. Nor is it required to ensure that the in-

service date for that facility will coincide with other upstream projects undertaken by Enbridge Energy or its affiliates.

Finally, Enbridge Energy had asked the Commission to defer addressing any timing issues relating to Line 61 until the second phase costs are included in a tariff filing. And Enbridge stated that it will not contend (or support any other party in contending) that Commission approval of the Supplement constitutes a determination that the second phase of the Line 61 Expansion is or will be used and useful at a particular time.

*****************************************************

ENERGY NEWS ALERT

On February 3 Louisiana Governor Bobby Jindal and Martin Houston, Chairman of Live Oak LNG, disclosed plans for a new natural gas liquefaction and export project in the Calcasieu waterway. The mid-sized project, costing upwards of $2 billion, is being designed for a plant capacity of up to five million tonnes per annum production and will include two 130,000 m3 storage tanks, and port facilities with a jetty for standard size liquefied natural gas (LNG) carriers. The proposed site is about 350 acres and is situated within Calcasieu Parish on the west bank of the Calcasieu River. Initial study work is already underway and Live Oak LNG will begin the permitting process within a few weeks. The anticipated start-up of the plant is in late 2019. Live Oak LNG is a fully owned subsidiary of Parallax Energy, a new company. Live Oak LNG and Parallax Energy are led by Martin Houston, former COO and Executive Director of BG Group plc. Houston is known for his efforts to turn the BG Group into a major global LNG business.



We greatly appreciate the incentives available, and the support of local officials who have already provided a wealth of information to get us started,” said Houston.

Governor Jindal stated that the project “is a welcome addition to the wealth of major industrial projects in Southwest Louisiana that are capitalizing on our state’s energy infrastructure and our outstanding, skilled workforce. The global demand for affordable, American-produced liquefied natural gas is on the rise, and Calcasieu Parish is ideally situated to serve that market with its deepwater ports and ready access to natural gas supplies. Louisiana’s top-ranked business climate is attracting more and more companies to make major investments here, including important energy projects like Live Oak LNG.”

Governor Jindal and Houston made the announcement in The Southwest Louisiana Entrepreneurial and Economic Development Center (SEED), along with the Southwest Louisiana Economic Development Alliance (SWLA) and Louisiana Economic Development (LED).

Parallax said it is an energy firm that is developing global liquefied natural gas (LNG) projects and a gas supply and trading business.

*****

In its Fourth Quarter and Annual Report to shareholders, BG Group said its Lake Charles LNG project remains one of the most competitive new supply sources for liquefied natural gas benefitting from existing infrastructure and access to a highly developed and liquid gas market. The FERC issued its Notice of Schedule for Environmental Approval for the project on January 26 and BG Group expects FERC authorization for the project in late 2015. The Group affirmed in its report that it continues to monitor the commodity price

environment and any impact this may have on construction costs. But BG Group now expects a decision whether to fully invest in the project in 2016.

Revenue and other operating income decreased 19% to $4,403 million for the BG Group in the last quarter 2014, “reflecting the significant fall in realized commodity prices combined with lower volumes in both the Upstream and LNG Shipping & Marketing segments, partially offset by hedging gains.” Brent oil hedges, entered into in the first quarter of 2014, gave rise to realized gains of $229 million, almost all of which were recognized in the upstream segment. Total operating profit decreased 36% to $1,224 million. Upstream segment total operating profit decreased 42% to $645 million, reflecting lower revenues. LNG Shipping & Marketing segment total operating profit decreased 32% as a result of lower revenues combined with higher costs of supply reflecting the increased number of spot cargo purchases.

For the past year, BG Group revenue and other operating income increased 2% to $19,546 million, driven by the LNG Shipping & Marketing segment which benefited from higher realized prices in the first half of 2014 and the end of the Group’s historical LNG hedge program. Total operating profit decreased 14% to $6,537 million. LNG Shipping & Marketing total operating profit decreased as a result of lower margins.

*****

On Feb. 2, Anadarko Petroleum Corp. announced 2014 fourth-quarter results, reporting a net loss attributable to common stockholders of $395 million, or $0.78 per share (diluted). Cash flow from operating activities in the fourth quarter of 2014 was $1.952 billion, and discretionary cash flow totaled $2.412 billion. For the year ended Dec. 31, 2014, Anadarko reported a net loss attributable to common stockholders of



$1.750 billion, or $3.47 per share (diluted), which includes a net loss of $4.045 billion associated with the settlement of the Tronox Adversary Proceeding, after tax. Full-year 2014 cash flow from operating activities was $8.466 billion. Discretionary cash flow for the year totaled $9.404 billion.

Moody's upgraded Anadarko Petroleum’s and its guaranteed subsidiaries, including Kerr-McGee Corp. and Union Pacific Resources Group Inc.'s, senior unsecured ratings to Baa2 from Baa3. The outlook was changed to stable from positive. The credit agency’s action follows the completion of “the Tronox litigation settlement” and the replacement of the company's senior secured revolving credit facility with unsecured credit facilities. According to Pete Speer, Moody's Senior Vice President, "Anadarko's low cost structure and capital flexibility will enable it to weather this low oil price environment consistent with its Baa2 exploration and production company peers." A ratings upgrade is unlikely in 2015 given the weak oil price environment. Anadarko Petroleum is headquartered in The Woodlands, Texas and is among the largest independent exploration and production companies.

Anadarko's full-year sales volumes of natural gas, crude oil and natural gas liquids (NGLs) totaled a record 306 million BOE, or an average of 838,000 BOE per day, on a divestiture-adjusted basis. Fourth-quarter 2014 sales volumes of natural gas, crude oil and NGLs totaled 79 million BOE, or an average of 854,000 BOE per day. Anadarko organically added 503 million BOE of proved reserves in 2014 before the effects of price revisions and incurred oil and natural gas exploration and development costs of approximately $8.8 billion. The company estimates its proved reserves at year-end 2014 totaled approximately 2.86 billion BOE, with 69% of its reserves categorized as proved developed. At year-end 2014, Anadarko's

proved reserves were comprised of 49% liquids and 51% natural gas.

In 2014, Anadarko's U.S. onshore operating areas achieved a 16% year-over-year increase in total sales volumes, including an increase of 78,000 bpd in liquids volumes, and an approximate 50% increase, or 49,000 BOPD, in oil volumes on a divestiture-adjusted basis. This growth was driven by record production in several major growth plays, including the Wattenberg field, Eagleford Shale and Wolfcamp Shale.

*****

Chesapeake Utilities Corp. and Gatherco, Inc. entered into a merger agreement, dated as of January 30, under which Chesapeake Utilities will acquire Gatherco. Upon consummation of the transaction, Gatherco will merge into Aspire Energy of Ohio, LLC, a wholly-owned subsidiary of Chesapeake Utilities. The acquisition of Gatherco positions Chesapeake Utilities in the middle of the shale production area in Ohio. The portion of the shale basin in eastern Ohio is the newest, and therefore least developed, shale play in the U.S. The merger, which is expected to close in the second quarter of 2015, is subject to approval by the Gatherco shareholders. Chesapeake Utilities stockholder approval of the merger is not required. Management expects the transaction to be accretive in 2016 – the first full year of operation following the merger. The transaction has an aggregate value of approximately $59.2 million.

Gatherco is a natural gas infrastructure company providing natural gas midstream services. Gatherco was established in 1997 in conjunction with the acquisition of Columbia Gas Transmission's natural gas gathering assets in Ohio. Gatherco's assets include 16 gathering systems and over 2,000 miles of pipelines in Central and Eastern Ohio. Gatherco provides natural gas gathering services and natural gas liquid processing services to over 300 producers, and supplies



natural gas to over 6,000 customers in Ohio through the Consumers Gas Cooperative, an independent entity which Gatherco manages under an operating agreement.

Chesapeake Utilities' current business includes both midstream and downstream natural gas operations. Eastern Shore Natural Gas Co., the company's interstate pipeline subsidiary, and Peninsula Pipeline Co., the company's Florida intrastate pipeline subsidiary, collectively represented approximately 30% and 28% of Chesapeake Utilities' total investment and net income as of the 12 months ended 9/30/14, respectively. In addition, Chesapeake Utilities has owned and operated several unregulated energy businesses.

*****

On 2/3/15 Continental Resources, Inc. announced proved reserves of 1.35 billion barrels of oil equivalent (Boe) at December 31, an increase of 267 million barrels of oil equivalent (MMBoe) or 25% compared with year-end 2013. Year-end 2014 proved reserves were 83% operated by the company, 36% proved developed producing (PDP), and 64% crude oil. Continental has grown its proved reserves at a compound annual growth rate of 39% per year since year-end 2010.

Harold G. Hamm, Chairman and Chief Executive Officer, commented, "2014 marks the 7th straight year since our IPO we have consistently delivered significant reserve and production growth. Our core assets in the Bakken of North Dakota and SCOOP Woodford/Springer in Oklahoma continue to provide exceptional results and are a testament to the quality of the base assets and the ability of our teams.” Estimated total production for full-year 2014 was 63.6 MMBoe, an increase of 28% compared to full-year 2013. Crude oil accounted for 70% of total production, or 44.5 million barrels, in 2014. Estimated natural gas production for the year was 114.3 Bcf. The company reached a new net production

milestone of 200,000 Boe per day in late December 2014.

*****

Richmond, Virginia-based Dominion closed the purchase of Carolina Gas Transmission (CGT) from SCANA Corp. for $492.9 million, the company said. CGT resulted from the 2006 merger of SCG Pipeline and South Carolina Pipeline, both SCANA subsidiaries. CGT delivers about 700 MMcf/d of gas to wholesale and direct industrial customers in South Carolina. Three new projects would increase its system’s capacity to approximately 820 MMcf/d by 2018.

*****

On 2/2/15 the EnLink Midstream companies, EnLink Midstream Partners, LP and EnLink Midstream, LLC (the General Partner) announced that the Partnership signed a definitive agreement to acquire Coronado Midstream Holdings LLC, which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600 million, subject to certain adjustments. Coronado’s key producer customers include Reliance Energy, Inc., Diamondback Energy, Inc., and RSP Permian, Inc. Reliance is currently the largest owner of Coronado, with affiliates of both Diamondback and RSP Permian owning the remainder of Coronado.

Coronado operates three cryogenic gas processing plants and a gas gathering system in the North Midland Basin including approximately 270 miles of gathering pipelines, 175 MMcf/d processing capacity and 35,000 horsepower of compression. Construction of an additional 100 MMcf/d of processing capacity and gathering system expansions of the Coronado system are underway. Coronado's key assets have been constructed within the past five years and the system has current inlet volumes of approximately 100 MMcf/d. EnLink plans to connect the Coronado system with its Bearkat system.



The owners of Coronado will receive $240 million in cash, $180 million of Partnership common units and $180 million of a new class of Partnership common units, subject to certain adjustments. “This transaction builds on EnLink’s growing midstream platform in West Texas,” said Barry Davis, EnLink President and Chief Executive Officer.

“In just over four months, we have announced approximately $1 billion of acquisitions, which is consistent with our growth strategy to expand our platform in key producing areas,” Davis added. According to Davis, the region has seen a rapid transition to horizontal drilling, with producers targeting the Lower Spraberry, Wolfcamp B, and Wolfcamp D zones among other prospective intervals.

EnLink Midstream was formed through the combination of Crosstex Energy and substantially all of the U.S. midstream assets of Devon Energy. Based in Dallas, Texas, EnLink Midstream’s assets include approximately 8,800 miles of gathering and transportation pipelines, 13 processing plants with 3.4 Bcf/d of net processing capacity, seven fractionators with 252,000 barrels per day of net fractionation capacity, as well as barge and rail terminals, product storage facilities, brine disposal wells, an extensive crude oil trucking fleet and equity investments in certain private midstream companies.

*****

FERC staff announced it will prepare an environmental assessment (EA), rather than a more thorough environmental impact statement (EIS), on Transcontinental Gas Pipe Line’s proposed 1.2 Bcf/d backhaul project to the Sabine Pass LNG export terminal in Louisiana. Transco’s Gulf Trace Expansion Project (CP15-29) would backhaul 1.2 Bcf/d of gas to the Sabine Pass terminal. The scoping period will last until March 6.

Gulf Trace would provide firm transportation capacity from Transco’s Station 65 in St.

Helena Parish, Louisiana, southward through the existing mainline and Southwest Louisiana Lateral, to a new 7-mile lateral linking up with the Sabine Pass terminal. The project is currently estimated to cost about $278 million.

Cheniere Energy is building four liquefaction trains at the Sabine Pass terminal, with a production capacity totaling the LNG equivalent of 2.76 Bcf/d of gas. Gulf Trace would supply gas required to feed Trains 3 and 4 at the terminal, according to Transco. Transco is targeting 1/1/17 as the in-service date.

*****

Plains All American Pipeline said Thursday that it will construct two crude oil pipelines and gathering systems as part of its Blacktip pump station expansion in Texas. The company will build a 32-mile extension of its Avalon pipeline, which is expected to ship up to 100,000 bpd of oil starting in July. It will also construct a 60-mile pipeline to carry up to 150,000 bpd of crude and condensate from the Delaware Basin to some New Mexico and Texas counties starting early next year.

These new infrastructure builds in West Texas and New Mexico will support PAA's previously announced 24-inch diameter Basin Pipeline loop from Wink to Midland and new 12-inch diameter pipeline from Monahans to Crane. The new Delaware Basin pipelines, Avalon Extension and State Line, are backed by producer commitments.

The 32-mile, 12 inch diameter Avalon Extension pipeline will extend the Avalon pipeline, which runs from the PAA Avalon station in northwest Loving County to its Blacktip station in southeast Loving County, Texas, into Culberson County, Texas, and is capable of transporting up to 100,000 bpd of crude oil from northern Loving and Culberson Counties. The line and two new truck unloading facilities at Orla, Texas are expected to be brought into service in phases beginning



in July 2015, with total system completion, including the associated gathering system, scheduled for September 2015. The 60-mile, 16-inch diameter State Line pipeline will connect Culberson County to Wink, Texas, running along the Texas-New Mexico state line. State Line will connect Delaware Basin production in southern Eddy and Lea Counties in New Mexico and northern Loving, Reeves and Culberson Counties in Texas to the existing network of PAA Permian Basin assets. The pipeline will be capable of transporting up to 150,000 bpd of batched crude oil and condensate. State Line is expected to be brought into service in phases beginning in early 2016 and concluding in mid-2016, with completion of the associated gathering system anticipated by early 2016.

*****

On February 05, Moody's Investors Service said that CNOOC LTD.’s plan to reduce capital spending and increase production volumes are credit positive because it will mitigate the negative impact of falling crude oil prices on the company's EBITDA and debt metrics. The plan is also credit positive for CNOOC Ltd.’s parent, China National Offshore Oil Corp., because CNOOC Ltd. accounts for the majority of CNOOC Group's profits.

Two days earlier, on 2/3/15 CNOOC Ltd. said it plans to reduce capital spending by 26%-35% in 2015 from the estimated realized capital expenditure in 2014 and increase production volumes by 10%-15%.

*****

Moody's says that while the sharp decline in crude oil prices since mid-2014 will weaken the exploration and production (E&P) businesses of China's three national oil companies (NOCs), the companies' overall credit quality will remain stable. The three companies are China National Petroleum Corp., China Petrochemical Corp. and China National Offshore Oil Corp. (CNOOC).

Also, on 2/5/15 Moody's said that the sharp decline in crude oil prices since mid-2014 will benefit most Asia Pacific sovereigns, given the region's status as a net oil importer. "As long as oil prices remain low, the direct effects will be positive on trade balances and downward on inflation in most Asian countries," said Thomas Byrne, a Moody's Senior Vice President/Manager, Asia Pacific and Middle East. Crude prices more than halved between June 2014 and January 2015, reflecting higher-than-expected oil production in the US and lower demand in emerging markets. Moody's has lowered its price assumptions for Brent crude to $55/barrel through 2015 and $65/barrel in 2016. While it expects oil prices to eventually rebound as demand increases and low prices create an eventual supply response as producers reduce their capital spending, this supply response will not be meaningful until at least 2016.

*****

American Energy Alliance President Thomas Pyle issued a statement supporting a Rep. Bob Goodlatte bill to reform the Renewable Fuel Standard (RFS). "We are encouraged by Rep. Goodlatte’s effort to fully repeal the Renewable Fuel Standard. Not only is the RFS an ill-advised policy that raises food and fuel prices for American families, but the EPA has demonstrated they are incapable of administering the mandate by failing to set guidelines for both 2014 and 2015,” said Pyle.

*****

Kent Larson, Executive Vice President and Group President, Operations at Xcel Energy Inc., based in Minneapolis, Minn., will chair the American Gas Association (AGA) Board Safety Committee in 2015, AGA announced Thursday, February 5. As Chairman, Larson will lead industry efforts to further enhance the strong safety performance of America’s local natural gas utilities. “Safety is a core value for AGA and our more than 200 member companies, and the AGA Board



Safety Committee helps direct and guide our many ongoing efforts to enhance safety,” said AGA President and CEO Dave McCurdy. The AGA Board Safety Committee was created in 2007.

*****

SSG Capital Advisors, LLC, an independent special situations investment bank, is forming a new group “dedicated to advising middle market companies in the energy industry.” In “perhaps one of the most challenging business climates this industry has experienced in recent years, energy companies are confronted with liquidity and cash flow constraints, falling asset values and an imbalance of supply and demand in the energy value chain," said Mark Chesen, SSG Managing Director.

*****

NGVAmerica lauded Sen. Michael Bennet (D-CO) and Richard Burr (R-NC) for reintroducing a bill (S. 344) to create a level playing field for clean-burning natural gas to compete with diesel as a transportation fuel. Currently, LNG is taxed at a rate 70% higher than diesel fuel on an energy content basis, “working against adoption of natural gas vehicles in the heavy truck market. Resetting the tax rate so that it is applied on an energy content, rather than volume basis is a commonsense measure that would remove an artificial barrier from the market.”

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EIA’S GAS STORAGE AND WEEKLY ANALYSIS

Working gas in storage was 2,428 Bcf as of Friday, January 30, according to EIA estimates. This represents a net decline of 115 Bcf from the previous week. Stocks were 468 Bcf higher than last year at this time and 29 Bcf below the 5-year average. In the East Region, stocks were 22 Bcf below the 5-year average. Stocks in the Producing Region were 24 Bcf below the 5-year average and stocks in the West were 17 Bcf above the 5-year average. At 2,428 Bcf, total working gas is within the 5-year historical range.

Weekly Update (for week ending Wednesday, February 4). Natural gas spot prices responded to regional weather, including severe winter conditions in the Midwest and Northeast. The Henry Hub spot price fell 16¢ from $2.89/MMBtu on January 28 to $2.73/MMBtu on February 4. At the New York Mercantile Exchange (Nymex), the price of the March 2015 futures contract opened the report week at $2.842/MMBtu and then moved down, with some minor fluctuation, to settle at $2.662/MMBtu.

The total U.S. rotary rig count decreased by 90 units to 1,543 rigs for the week ending January 30, 14% less than a year ago, according to data from Baker Hughes Inc. The natural gas rig count rose by 3 units to 319, while oil rigs fell by 94 to 1,223. EIA said that largest decline in oil rigs occurred in the Permian, where the count fell by 27.

WORKING GAS IN UNDERGROUND STORAGE FOR WEEK ENDING January 30, 2015

Region

Current Week Stocks (Bcf)

Prior Week Stocks (Bcf)

Net

Change (Bcf)

Year Ago

Stocks (Bcf)

5-Yr Average Stocks

(2010-2014)

Cur Wk Difference

from 5 Yr Avg (%)

East 1,194 1,281 -87 940 1,216 -1.8

West 371 375 -4 305 354 4.8

Producing 863 887 -24 715 887 -2.7

Total Lower-48 2,428 2,543 -115 1,960 2,457 -1.2

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