IN THE MATTER OF

the Utilities Commission Act, RSBC 1996, Chapter 473

 

and

 

Pacific Northern Gas Ltd.

An Application for No changes to 2015 Delivery Rates and

Changes to the 2015 Revenue Stabilization Adjustment Mechanism Rider

for the PNG-West Service Area

 

 

BEFORE:               Carol Brown, Panel Chair/Commissioner

                                Karen Keilty, Commissioner                                        June 18, 2015

                                David Morton, Commissioner

 

O  R  D  E  R

 

WHEREAS:

 

A.      On November 28, 2014, Pacific Northern Gas Ltd. (PNG) filed with the British Columbia Utilities Commission (Commission), pursuant to sections 59 to 61, 89 and 90 of the Utilities Commission Act (UCA), an Application for No Changes to 2015 Delivery Rates and Changes to the 2015 Revenue Stabilization Adjustment Mechanism (RSAM) Rider (Original Application);

 

B.      In the Original Application, PNG requested approval to:

•         Maintain the current 2014 delivery rates approved by Order G-87-14 on a permanent basis, effective January 1, 2015;

•         Change the RSAM rider, on an interim basis, effective January 1, 2015;

•         Make changes to its deferral accounts as set forth in the Application;

•         Drawdown sufficient amortization of the LNG Partners Option Fee deferral account to reduce its forecast revenue deficiency to a nil balance once the actual 2014 year end balances have been determined and reflected in the determination of its forecast 2015 revenue deficiency requirement. In the event that a revenue sufficiency occurs, PNG requests approval to create a new deferral account to capture the forecast revenue sufficiency in 2015;

 

C.      On December 12, 2014, Commission Order G-195-14 approved the retention of the current delivery charge component of customer rates, and the change to the RSAM rate rider as set forth in the Original Application on an interim and refundable basis, effective January 1, 2015, and established a Preliminary Regulatory Timetable;

 

D.      On January 12, 2015, British Columbia Old Age Pensioners’ Organization, Active Support Against Poverty, Disability Alliance BC, Council of Senior Citizens’ Organizations of BC, and the Tenant Resource and Advisory Centre registered as the sole intervener in this proceeding;

 

E.       On March 9, 2015, PNG filed an amended application (Application) that included an increase in the forecast a revenue deficiency to $175,000, up from $117,000 in the Original Application, and the following requests:

•         Approval to maintain the current 2014 delivery rates approved by Order G-87-14 on a permanent basis, effective January 1, 2015;

•         Approval of an annualized RSAM rate rider of $0.243/GJ, down from $0.452/GJ in the Original Application;

•         Approval of the changes to PNG’s deferral accounts as detailed in the Application (Table 4);

•         Approval to vary Order G-87-14, to not fully amortize the LNG Partners Option Fee deferral account at the end of 2014, and only drawdown the amount of $175,000 to reduce the 2015 revenue deficiency to a nil amount;

 

F.       In the Application, PNG stated that a simplified regulatory process would be the most efficient process for the review of the Application;

 

G.     On March 30, 2015, the Commission invited interveners to make submissions regarding regulatory process, including whether there is sufficient evidence on the record concerning PNG’s 2015 revenue requirement forecast or whether a round of information requests is required. Interveners were invited to make submissions by Tuesday, April 7, 2015, and PNG to file its reply submission by Tuesday, April 14, 2015;

 

H.      On April 28, 2015, Commission Order G-66-15 amended the regulatory timetable established by Order G‑195‑14, and established a Streamlined Review Process (SRP) for the review of the Application. The SRP was held on June 3, 2015; and

 

I.        The Commission considered the Application, evidence and submissions of the parties as set forth and discussed in the Reasons for Decision attached as Appendix A to this order.

 

 

NOW THEREFORE pursuant to sections 57, 59 to 61, 89 and 90 of Utilities Commission Act, for the reasons attached as Appendix A, the Commission orders as follows:

 

1.       Pacific Northern Gas Ltd. (PNG) will maintain the current 2014 delivery rates approved by Order G-87-14 on a permanent basis, effective January 1, 2015.

 

2.       The annualized Revenue Stabilization Adjustment Mechanism rider is approved on a permanent basis at $0.243/GJ, effective January 1, 2015.

 

3.  The requested changes to the deferral accounts as set forth in the Application (Table 4) are approved as modified to reflect the directives in this Order.

 

4.       Order G-87-14 is varied to eliminate the requirement to amortize the LNG Partners Option Fee deferral account in 2015.

 

5.       PNG must establish a 2015 revenue deficiency regulatory account for the adjusted revenue deficiency, which is $175,000, less the adjustments as directed by the Commission in this order.

 

6.       The Cost of Service and resulting revenue deficiency as applied for, is approved, with the following noted variations, summarized as follows:

a.       PNG must revise the demand forecast for the residential use per account (UPA) by using the previous forecast methodology, which will reduce the revenue deficiency by $42,000; and

b.      PNG must revise the cost of service forecast by reducing the recovery of the AltaGas Inter-Affiliate charge to $715,000, which will reduce the revenue deficiency by $12,000.

 

7.       Pacific Northern Gas Ltd. must comply with the following directives in its 2016/2017 Revenue Requirement Application:

a.       Address the proposed recovery mechanism and amortization period for the 2015 revenue deficiency regulatory account;

b.      Address the proposed recovery mechanism and amortization period of LNG Partners Option Fee deferral account as part of the filing in which it addresses the recording of additional option fees and recording of revenue received services commencing under the Gas Transportation Supply Agreement, as required under Order G-5-15;

c.       File a regulatory account report detailing the carrying value of PNG’s regulatory account balances, a description of the type, nature and purpose of each account, and the proposed or previously approved recovery mechanism, amortization period and carrying costs;

d.      Prepare a fulsome analysis of the accuracy of the proposed methodology for the residential UPA forecast, including a comparison of the existing methodology and the proposed methodology and actuals for 2015, and if feasible for the five previous years;

e.      Address the issue of the 2012 Common Equity Thickness deferral account, including an analysis for whether this benefits the ratepayers, and the proposed amortized period; and

f.        Provide a full review and analysis of the AltaGas Inter-Affiliate Charges for 2016/2017 forecast, including the filing of reliable and objective evidence to support proposed recovery of these charges.

 

8.       PNG is to provide a copy of this order, by email where possible, to all parties who participated in the PNG 2014 Revenue Requirements Application proceedings.

 

 

DATED at the City of Vancouver, in the Province of British Columbia, this                   18^th               day of June 2015.

 

                                                                                                                                BY ORDER

 

                                                                                                                                Original signed by:

 

C. A. Brown

                                                                                                                                Panel Chair/Commissioner

Attachment

 

 

Pacific Northern Gas Ltd.

An Application for No changes to 2015 Delivery Rates and

Changes to the 2015 Revenue Stabilization Adjustment Mechanism Rider

for the PNG-West Service Area

 

 

1.       Introduction

 

Pacific Northern Gas Ltd. (PNG) filed an application on November 28, 2014, pursuant to sections 59 to 61, 89 and 90 of the Utilities Commission Act (UCA), with the British Columbia Utilities Commission (Commission), requesting no changes to 2015 Delivery Rates and changes to the 2015 Revenue Stabilization Adjustment Mechanism (RSAM) Rider. The Commission granted an interim order[1] on December 12, 2014, approving the following interim rates: retention of the current delivery charge component of customer rates and an increase to the RSAM rate rider on an interim and refundable basis. On March 9, 2015, PNG filed an amended application (Application),[2] with revised demand forecast and updated cost of service forecast reflecting the impact of incorporating the results of actual 2014 year-end balances and among other things, indicating a revenue deficiency of $175,000.

 

On April 28, 2015, Commission Order G-66-15 established a Streamlined Review Process (SRP) for the review of the Application. The SRP was held on, June 3, 2015.

 

In addition to, or related to the above-noted requests, the Panel also considered the following:

1.       Changes to deferral accounts as set forth in Table 4 of the Application;[3]

2.       A variation from Order G-87-14 to change the amortization of the LNG Partners Option Fee deferral account to $175,000 in 2015, reducing the forecast 2015 revenue deficiency to zero;[4]

3.       No change to the treatment of the 2012 Equity Thickness Deferral Account;[5]

4.       Changes to the forecast methodology for the use per account (UPA) respecting Residential Rates;[6]

5.       Cost of Service items[7], including:

a.       Recovery of $727,000 of the forecast $2.2 million AltaGas Inter-Affiliate charge;

b.      Approval of the Right-of-Way (ROW) forecast expense of $299,000; and

c.       Approval of the Operating and Maintenance, and Administrative and General Expense forecast,[8] which include the cost of workforce additions for a Director of Environment, Health and Safety, and a Human Resource Advisor.[9]

 

As provided in the attached order, the Panel has considered all of the evidence, and approves the Application, save and except that the Panel has varied specific elements of the Application identified in both the order and these Reasons. The Panel has considered issues regarding the following aspects of the Application, and has provided analysis and reasons in the following sections: amortization of the LNG Partners Option Fee; forecast for the Residential UPA; treatment of the 2012 Common Equity Thickness Deferral Account; and the previously referred to cost of service issues raised in the proceeding.

2.       AMORTIZATION OF THE LNG PARTNERS OPTION FEE DEFFERAL ACCOUNT

PNG and LNG Partners, LLC, (LNG Partners) were parties to a gas transportation services agreement, approved by the Commission on June 28, 2012.[10] PNG had received option fees from LNG partners to secure transportation capacity under the transportation services agreement, a portion of which was to be credited to transportation service fees if services commenced.[11] If the LNG Partners did not commence service as provided for under the terms of the agreement, the transportation services agreement would terminate, and PNG would retain the entire option fee.

 

This option fee was recorded in a regulatory account and was partially amortized to smooth rates over the last several years. The option under the transportation services agreement has not been exercised.

 

In the PNG 2014 Revenue Requirements Application (RRA), due to uncertainty that the LNG partners would exercise their option, PNG was directed to reduce the credit amortization of the LNG Partners Option Fee deferral account by $800,000 and reserve the balance for amortization in 2015.[12]

 

Recently, in a separate proceeding, the Commission approved an assignment of the LNG Partners option, with certain amendments, and a new Gas Transportation Services Agreement between PNG and EDF Trading Limited, dated December 12, 2014 (Transportation Agreement).[13] Pursuant to this agreement, PNG anticipates the receipt of $3,000,000 of additional option fees in the 2015 year, of which $2,000,000 was received in the first quarter of 2015.[14] At the SRP for this proceeding, the Panel determined that the issue of recording additional option fees and recording of revenue received when services commence under the Transportation Agreement, could be dealt with in the next PNG revenue requirements application or by separate application.

 

In this application, PNG proposes to reduce the 2015 revenue deficiency to zero, in order to avoid increasing rates in 2015. PNG prefers to offset the forecasted revenue deficiency of $175,000 using the LNG Partners Option Fee deferral account rather than creating a new deferral account due to the administrative costs that go along with setting up a new account and addressing amortization of the account in the future.[15] PNG submits that while a portion of the option fees received prior to January 1, 2015, is to be applied as a credit for future transportation services, amortizing $175,000 in 2015 does not put this credit at risk.[16]

 

Accordingly, in this application, PNG wishes to vary the directive in Order G-87-14 by amortizing only $175,000 of the December 31, 2014 balance in the LNG Partners Option Fee deferral account in 2015, which would reduce the forecasted revenue deficiency, as provided in the Application, to zero.

 

BCOAPO supports PNG’s application to modify the amortization LNG Partners Option Fee deferral account in order to achieve rate smoothing, subject to certain adjustments.[17]

 

Commission determinations

The Panel agrees with PNG and BCOAPO that an increase in permanent rates to cover the 2015 revenue deficiency may not be efficient or in the public interest, as PNG expects that rates may not increase over the long term and may actually drop in the near term. However, the Panel is not persuaded that PNG’s request to amortize $175,000 of the LNG Option Fee deferral account is the best approach. The Panel is concerned about the portion of the un-amortized option fees balance on December 31, 2014, to be credited against future transportation services under the Transportation Agreement, if the option is exercised.

 

The Panel acknowledges that the Commission previously directed PNG to amortize the LNG Option Fee deferral account balance in 2015.[18] This was based on PNG’s uncertainty as to the future of the LNG Partner’s Agreement. Today, there is evidence of greater certainty, in that PNG has received further options fees in 2015 and that the Commission has approved a new gas transportation agreement and assignment, and amendment of the previous option agreement[19] The Panel is of the view that the recovery mechanism and amortization period of remaining LNG Partners Option Fee deferral account is better addressed as part of the filing in which PNG will address the recording of additional option fees, and recording of revenue received when services commence under the new Transportation Agreement. The Commission can, at that time, review PNG’s proposed approach to the recovery mechanism for this account in the context of PNG’s policies with regard to its other regulatory accounts.

 

In order to smooth rates in the light of the revenue deficiency, the Panel is of the view that a new regulatory account is appropriate, and that creating a new regulatory account for the forecast 2015 revenue deficiency will not add any significant administrative costs.

 

For these reasons, the Panel:

1.       Directs PNG to establish a 2015 revenue deficiency regulatory account, for the forecast 2015 revenue deficiency of $175,000, less any adjustments ordered by the Panel herein, and to file its proposed recovery mechanism and amortization period of this regulatory account as part of its 2016/2017 RRA.

2.       Directs PNG to address its proposed recovery mechanism and amortization period of LNG Partners Option Fee deferral account, as of December 31, 2014, as part of the filing in which it addresses the recording of additional option fees and recording of revenue received, pursuant to Order G-5-15.

3.       Varies Order G-87-14, to change the amortization of the LNG Partner Option Fee deferral account to $0 in 2015.

4.       Directs PNG to file a regulatory account report in the 2016/2017 RRA, detailing the carrying value of PNG’s regulatory account balances, a description of the type, nature and purpose of each account, the proposed or previously approved recovery mechanism, amortization period and carrying costs.

3.       FORECAST FOR THE RESIDENTIAL UPA

PNG has made changes to its methodology for forecasting Residential UPA. It states that for the 2015 forecast, it “partially applied the methodology used in the 2014 PNG-West Resource Plan” in consideration of the Commission’s observations in that proceeding to harmonize the forecast and forecasting methodologies for all PNG’s filings. PNG then “applied a 50 percent weighting to the forecast UPA derived from the PNG-West 2014 Resource Plan methodology and a 50 percent weighting to the 2015 linear trend figure of 5-19 year historical normalized UPA used in the traditional methodology.”[20] PNG acknowledges that “applying a 50/50 weighting may be considered arbitrary” and as a result offers to evaluate this weighting in future revenue requirements filings.[21]

 

As a result of a modification to its forecasting methodology, PNG forecasts a decrease to the delivery margin by approximately $42,000.[22] PNG submits that if the old methodology had been used, although there would be a timing impact on customers, the overall impact would not be substantial. It further submits that had the old methodology been used and it was wrong in some way it would have resulted in the transfer from one deferral account to another.[23]

 

BCOAPO submits that PNG should use the existing methodology for 2015 and that PNG can apply to change the methodology in the next revenue requirements application. In its view “an SRP with a limited discovery process isn’t the place to change methodology[24]… issues in the SRP [should] be limited to things that are not methodological changes .”[25]

 

Commission determination

The Panel acknowledges PNG’s efforts to modify its methodology in response to comments made by the Commission in its previous Long Term Resource Plan (LTRP) proceeding. However PNG has provided no evidence that its proposed methodology is potentially any more accurate than its existing methodology. Further the Panel agrees with BCOAPO that this proceeding is not the place to make this change. PNG states that it will revaluate its proposed 50/50 weighting in future RRAs. Accordingly, the Panel directs PNG to revise the demand forecast using the previous forecast methodology. The Panel agrees with this approach and directs PNG, in the next RRA, to prepare a fulsome analysis of the accuracy of its proposed methodology. This analysis should include a comparison of the existing methodology and the proposed methodology and actuals for 2015 and, if feasible, for the five previous years.

 

The Panel notes that consequentially, by maintaining the existing forecasting methodology, a reduction in PNG’s revenue requirement of $42,000, from $175,000 to $133,000 will occur in 2015. If the actual UPA in 2015 does reflect the new forecast methodology, then all else being equal the $42,000 differential will end up in the RSAM account to be recovered in the following year. As PNG pointed out in its final submission, this is a timing difference only.

 

4.       2012 COMMON EQUITY THICKNESS DEFERRAL ACCOUNT

PNG redeemed its preferred shares on February 27, 2012. In the 2012 Revenue Requirement Application (2012 RRA), PNG sought approval to increase the common equity component of rate base capitalization from 45 percent to 46.5 percent.[26] The 2012 RRA Panel made the following determination:

The Commission Panel does not approve the Applicant’s proposed change to its 2012 capital structure, through raising the common equity component of the rate base by 1.5 percent to 46.5 percent from the 45 percent that was approved in Order G-84-10. The Panel expects that the appropriate capital structure and return on equity are being reviewed in the Generic Cost of Capital proceeding. However, the Panel does allow PNG to record the revenue requirement effect of its proposed increase in common equity from 45 percent to 46.5 percent, effective February 28, 2012, in a non-rate base deferral account attracting interest at the weighted average cost of debt. The disposition of this deferral account should occur in the next RRA, following the issuance of the Generic Cost of Capital decision.[27]

 

PNG, in the 2015 RRA[28] stated that it has not addressed the disposition of the 2012 Common Equity Thickness Deferral Account, in compliance with the 2012 and 2013 RRA decisions.

 

The Stage 2 Generic Cost of Capital Decision was issued on March 25, 2014.

 

When asked by Commission staff at the SRP why this account was not amortized in 2015, PNG responded by stating that the disposal of this deferral account should be reviewed in the 2016/2017 RRA. In the Application, PNG requested a simplified regulatory process.[29]

 

Commission determination

The Panel directs PNG, in the 2016/2017 RRA, to address the issue of the 2012 Common Equity Thickness deferral account, including an analysis of whether it benefits ratepayers, and how it should be amortized.

 

The Panel considers that the 2012 Common Equity Thickness deferral account should have been addressed in the 2015 Application. In the interest of regulatory efficiency, the Panel accepts PNG’s proposal to deal with it in the 2016/2017 RRA.

 

The Panel wishes to clarify a point of possible misunderstanding respecting the use of the SRP. Indeed, the SRP Guidelines suggest they can be used for smaller applications with a limited number of issues. The Panel distinguishes between a “simplified application” and an SRP. If an application is smaller, and fits into the criteria of the SRP Guidelines, then an SRP may be used for the review. However, more complex issues that are uncontested may also fit into the SRP guidelines. It is the Panel’s opinion that the Commission does not have a simplified application process, where parties can unilaterally decide to postpone the inclusion of certain issues in the application. Rather, the SRP is chosen when the application is appropriate – usually meaning a relatively simple application.

5.       COST OF SERVICE ISSUES

5.1               AltaGas Inter-Affiliate charges

AltaGas Ltd (AltaGas) finalized the purchase of 100 percent of the shares of PNG on December 20, 2011. Since then, PNG has experienced cost reductions as a result of PNG no longer being a publicly traded reporting company,[30] and cost increases related to an inter-affiliate charge from AltaGas.

 

For the 2015 test year, PNG has included $727,000 for the AltaGas Inter-Affiliate charge in the cost of service. PNG proposes to add an inflationary increase of 2 percent percent to the amount of the 2014 Inter-Affiliate charge that was included in the 2014 cost of service. PNG expects the 2015 AltaGas Inter-Affiliate charge to be $2.2 million.[31]

 

The Inter-Affiliate charge included in the 2012, 2013 and 2014 cost of service was $404,335,[32] $621,312[33] and $715,000[34] respectively.

 

BCOAPO suggested that the PNG proposal for the Inter-Affiliate charge be reduced, by adding only 1 percent inflation, instead of the 2 percent that was provided in the Application.[35]

 

Commission determination

In the absence of a study on actual charges, we cannot assess whether the affiliate charge should be increased or decreased. The Panel has reviewed the evidence, and is not persuaded there has been any change of circumstance since 2014, to support a change to the 2014 inter-affiliate charge for 2015. Therefore, the Panel denies PNG’s 2015 proposed Inter-Affiliate charge. Instead we allow PNG to recover $715,000 in the cost of service.

 

However, PNG should file with the Commission evidence that would support a future Commission decision on whether it is appropriate to maintain, increase, or decrease this charge in future years. The Panel is specifically interested in objective evidence of the market value of the services provided. Accordingly, the Panel directs PNG to conduct a full review and analysis of the AltaGas Inter-Affiliate Charges for 2016/2017 forecast, including the filing of reliable and objective evidence, such as a third-party consultant’s report in the 2016/2017 RRA.

 

5.2               Right-of-Way forecast

 

PNG is requesting approval for an increase in Right-of-Way (ROW) clearing costs for 2015 of $299,000, which is $142,000 more than the 2014 actual ROW expense;[36] PNG submits that this is consistent with the 2011-2013 three-year average of $286,000. PNG contends that the variance over 2014 arises due to a budgeting oversight in the 2014 Negotiated Settlement Process leading to under-budgeting the usual level of work performed.[37]

 

BCOAPO queried the budgeting oversight[38] and whether the budget of $299,000 was based on an intuitive estimate or calculated from a list of projects.[39] PNG replied that they used a zero-based budgeting approach, and that the managers of each area responsible for the ROW were tasked with determining the work required for the 2015 fiscal year.[40]

 

In its final submission, BCOAPO requested that the ROW forecast be reduced by $13,000 to $286,000, in order to align with the 2011-2013 three-year average. BCOAPO noted that in any of the last four years, PNG has only spent over $266,000 once.

 

Commission determination

The Panel approves of the ROW forecast expense of $299,000 for the 2015 test year. While the Panel acknowledges that the forecast is much higher than the 2014 actual, and higher than the average for recent years ($286,000), the Panel accepts the evidence of PNG that the ROW expenses are based on identified ROW projects, which includes some work that was postponed from 2014 to 2015.[41] The Panel notes that the average of the 2015 forecast ($299,000) and the 2014 actual ($157,000) is $228,000. For these reasons, the Panel concludes that the ROW 2015 forecast is reasonable.

5.3   Operating, Maintenance, Administrative and General Expenses – Labour

The issue of labour costs was raised in the context of the Operating, Maintenance, Administrative and General Expenses. PNG forecasts a net increase of Operating and Maintenance Labour of $397,000 for 2015[42] and administrative and general expenses of $350,000.[43] In the Operating and Maintenance expenses category, PNG stated that the forecast includes a newly created position of Director of Environmental Health and Safety.[44] In the Administrative and General expenses category, a new Human Resource Advisor (HR Advisor) was added to the labour component.[45]

 

When asked about the increased labour cost forecast with respect to these two positions, PNG replied that the “fully-loaded annual cost of the two new positions is approximately $396,000.”[46]

 

Regarding the HR Advisor, PNG states that they replaced 10 percent of their workforce in 2014 have a significant number of employees eligible for retirement, and ongoing requirements for recruiting will become more challenging. PNG contends that this expense is more cost effective than its past practice of outsourcing recruiting to search firms.[47]

 

With respect to the Director of Environment Health and Safety, PNG stated that one person, who is now retired, was responsible for the documentation and liaison, respecting health and safety, and that there is now “increased liaison that [is] required.” He was the manager of community relations.[48] PNG provided that the net cost of the wages for this position is $82,000.[49]

 

BCOAPO submits that it agrees with PNG’s justification for the hiring of a new Human Resource person, with the current and proposed staffing changes at PNG.[50] However, BCOAPO submits that the addition of the position of the Director of Health and Safety, with a fully loaded cost of approximately $250,000, represents approximately a 1 percent increase to ratepayers, implying that it is excessive. BCOAPO submits that health and safety ought to be addressed in the ordinary course of business.[51] BCOAPO asked the following question at the SRP, in reference to the Director of Health and Safety position: “[n]o one actually had that as part of their job description prior to this new person being hired? It was just something they did off the side of their desks?”[52]

 

PNG responded to inquiries from BCOAPO, suggesting that the Oil and Gas Commission (OCG) has taken a more proactive and increased role in health and safety issues, including training, emergency response, and first responders. In addition, the OGC requires more comprehensive planning documents and have opened up an office in Terrace.[53]

 

Commission determination

The Panel approves the increase to the Operating, Maintenance, Administrative and General expenses. The Panel has reviewed the evidence and finds that PNG’s explanation for those forecast increases are reasonable.

 

The issue of the Operating, Maintenance, Administrative and General expense forecast was raised in terms of labour costs.

 

The Panel accepts PNG’s justification, and BCOAPO’s agreement, that the HR Advisor would be engaged in recruiting activities, which is more cost-effective than outsourcing to search firms[54] and find that this expense is reasonable.

 

The Panel acknowledges BCOAPO’s concerns that the addition of the Director of Environment Health and Safety is an added expense, and at $296,000 representing 1 percent of the cost of service, which is not insignificant. Further, while the Panel supports BCOAPO’s principled approach that PNG as a whole should deal with health and safety in the ordinary course of business, the Panel sees the addition of a Director of Health and Safety as an addition to, and not in place of, PNG having a corporate culture that supports health and safety in the ordinary course. The Panel is persuaded by the fact that the employee, who was responsible for health and safety compliance filings, retired and that the net increase in cost for this position is $82,000. The Panel is further persuaded by PNG’s evidence that the Oil and Gas Commission has taken a more active role in pipeline regulation, which has impacted PNG’s Health and Safety Activity level.