ITEM 2 – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, Resources may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. These statements are based on management’s current expectations and information available at the time of such statements and are believed to be reasonable and are made in good faith. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include, but are not limited to those set forth in the following discussion and within Item 1A “Risk Factors” in the Company’s 2018 Annual Report on Form 10-K. All of these factors are difficult to predict and many are beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company’s documents or news releases, the words, “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “budget,” “assume,” “indicate” or similar words or future or conditional verbs such as “will,” “would,” “should,” “can,” “could” or “may” are intended to identify forward-looking statements.
Forward-looking statements reflect the Company’s current expectations only as of the date they are made. The Company assumes no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations.
The three-month and nine-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2019. The total revenues and margins realized during the first nine months reflect higher billings due to the weather sensitive nature of the natural gas business.
Overview
Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 60,900 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding localities through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for terms and conditions set by the Virginia State Corporation Commission (“SCC”).
Resources also invests in the Mountain Valley Pipeline ("MVP"), an interstate pipeline currently under construction, as a 1% participant through its RGC Midstream, LLC subsidiary ("Midstream") in addition to providing certain unregulated services through Roanoke Gas and its other subsidiaries. The unregulated operations of Roanoke Gas represent less than 2% of total revenues of Resources on an annual basis.
The Company’s utility operations are regulated by the SCC, which oversees the terms, conditions, and rates to be charged to customers for natural gas service, safety standards, extension of service, accounting and depreciation. The Company is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. The Federal Energy Regulatory Commission ("FERC") regulates the prices for the transportation and delivery of natural gas to the Company’s distribution system and underground storage services. The Company is also subject to other regulations which are not necessarily industry specific.
Over 98% of the Company’s annual revenues, excluding equity in earnings of MVP, are derived from the sale and delivery of natural gas to Roanoke Gas customers. The SCC authorizes the rates and fees the Company charges its customers for these services. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather. Normal weather refers to the average number of heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) over the previous 30-year period.
The Company currently has a non-gas base rate application pending before the SCC. Roanoke Gas implemented the non-gas rates contained in its rate application for natural gas service rendered to customers on or after January 1, 2019. These non-gas rates are subject to refund pending audit, hearing and a final order issued by the SCC. On June 28, 2019, the SCC staff issued its report and findings from the audit of the rate application. The SCC staff recommended a lower non-gas rate increase requested in the rate application, which is normal and expected. Management provided additional testimony and rebuttal to
RGC RESOURCES, INC. AND SUBSIDIARIES
certain proposed adjustments in response to the SCC staff report. As a result of its review of the proposed adjustments by the SCC and assessment of its position regarding such adjustments, management has established a provision for the estimated refund. In addition, the SCC staff recommended a change in rate design of the non-gas rate increase between customer base charge and volumetric rates, shifting much of the increase in non-gas rates from customer base charge to the volumetric components.
A hearing is scheduled for August 14, 2019 in which the Company will respond to the proposed adjustments to the rate filing. The hearing examiner's report is expected to be issued after the fiscal year end with a final order not expected until late first quarter or early second quarter of fiscal 2020 with customer refunds completed once the order is received.
The Company has completed the transition to the 21% federal statutory income tax rate as a result of the Tax Cuts and Jobs Act ("TCJA") that was signed into law in December 2017. Since the implementation of the new tax rates, the Company has recorded a provision for refund related to estimated excess revenues collected from customers under approved billing rates designed to recover expenses and provide a rate of return based on a federal tax rate of 34%. Beginning January 1, 2019, Roanoke Gas incorporated the effect of the 21% federal tax rate with the implementation of new non-gas base rates, as filed in its current rate application, and began refunding the excess revenues associated with the change in the tax rate over the subsequent 12-month period. The Company also recorded a regulatory liability related to the excess deferred income taxes on the regulated operations of Roanoke Gas. These excess deferred income taxes are being refunded to customers over a 28-year period. The SCC staff report indicated no changes to the amounts for excess revenue collected and the excess deferred taxes to be refunded to customers. The Company expects to complete the refund of the excess revenues by December and will continue to refund the excess deferred taxes over time. Additional information regarding the TCJA and non-gas base rate application is provided under the Regulatory and Tax Reform section below.
As the Company’s business is seasonal in nature, volatility in winter weather and the commodity price of natural gas can impact the effectiveness of the Company’s rates in recovering its costs and providing a reasonable return for its shareholders. In order to mitigate the effect of variations in weather and the cost of natural gas, the Company has certain approved rate mechanisms in place that help provide stability in earnings, adjust for volatility in the price of natural gas and provide a return on increased infrastructure investment. These mechanisms include a purchased gas adjustment factor ("PGA"), weather normalization adjustment factor ("WNA"), inventory carrying cost revenue ("ICC") and a Steps to Advance Virginia's Energy Plan ("SAVE") adjustment rider.
The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. The cost of natural gas is considered a pass-through cost and is independent of the non-gas base rates of the Company. This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations. On a quarterly basis, or more frequently if necessary, the Company files a PGA rate adjustment request with the SCC to adjust the gas cost component of its tariff rates depending on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as those amounts are reflected in customer billings.
The WNA model reduces earnings volatility, related to weather variability in the heating season, by providing the Company a level of earnings protection when weather is warmer than normal and providing customers some price protection when the weather is colder than normal. The WNA is based on a weather measurement band around the most recent 30-year temperature average. Under the WNA, the Company recovers from its customers the lost margin (excluding gas costs) for the impact of weather that is warmer than normal or refunds the excess margin earned for weather that is colder than normal. The WNA mechanism used by the Company is based on a linear regression model that determines the value of a single heating degree day. For the three months and nine months ended June 30, 2019, the Company accrued $461,000 and $350,000 in additional revenues under the WNA model for weather that was 46% and 3% warmer than normal, respectively. For the corresponding periods last year, the Company accrued approximately $80,000 in additional revenues for weather that was 9% warmer than normal, and approximately $43,000 reduction in revenues for weather that was 1% colder than normal. The WNA year runs from April 1 to March 31 each year.
The Company also has an approved rate structure in place that mitigates the impact of financing costs associated with its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue for the financing costs, or “carrying costs,” of its investment in natural gas inventory. This ICC factor applied to the cost of inventory is based on the Company’s weighted-average cost of capital including interest rates on short-term and long-term debt and the Company’s authorized return on equity. During times of rising gas costs and rising inventory levels, the Company recognizes ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and lower inventory balances,
RGC RESOURCES, INC. AND SUBSIDIARIES
the Company recognizes less carrying cost revenue as financing costs are lower. In addition, ICC revenues are impacted by the changes in the weighting of the components that are used to determine the weighted-average cost of capital. Total ICC revenues for the three and nine month periods ended June 30, 2019 declined by approximately 22% and 14%, respectively, from the same periods last year due to a combination of lower average natural gas storage balances and a reduction in the weighted average cost of capital factor used in calculating these revenues.
The Company’s non-gas base rates provide for the recovery of non-gas related expenses and a reasonable return to shareholders. These rates are determined based on the filing of a formal non-gas rate application with the SCC utilizing historical and proforma information, including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the non-gas base rates currently in place. The additional investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is filed and approved. The SAVE Plan, however, provides the Company with the ability to recover costs related to investments in qualified infrastructure projects on a prospective basis. The SAVE Plan provides a mechanism through which the Company may recover the related depreciation and expenses and provides a return on rate base for the related additional capital investments until such time that a formal rate application is filed. As the Company has made significant expenditures since the last non-gas base rate increase in 2013, SAVE Plan revenues have continued to increase each year. With the filing of the new non-gas rate application, the SAVE Plan program has been reset as the prior qualified infrastructure investments were included in the derivation of the non-gas rates placed into effect in January 2019. Accordingly, SAVE Plan revenues declined by $1,143,000 for the three-month period ended June 30, 2019 compared to the same period last year and by approximately $2,157,000 for the corresponding nine-month periods.
The Company is committed to safeguarding its information technology systems. These systems contain confidential customer, vendor and employee information as well as important financial data. There is risk associated with unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions or compromise information. Management believes it has taken reasonable security measures to protect these systems from cyber attacks and similar incidents; however, there can be no guarantee that an incident will not occur. In the event of a cyber incident, the Company will execute its Security Incident Response Plan. The Company maintains cyber insurance to mitigate financial exposure that may result from a cyber incident.
Results of Operations
Three Months Ended
June 30, 2019
:
Net income increased by $51,200 for the three months ended
June 30, 2019
, compared to the same period last year. Quarterly performance improved slightly as the impact of the rate increase combined with the earnings on the Mountain Valley Pipeline investment offset increases in operation and maintenance costs and interest expense.
The tables below reflect operating revenues, volume activity and heating degree-days.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
|
|
2019
|
|
2018
|
|
Increase / (Decrease)
|
|
Percentage
|
Operating Revenues
|
|
|
|
|
|
|
|
Gas Utility
|
$
|
11,534,948
|
|
|
$
|
11,546,797
|
|
|
$
|
(11,849
|
)
|
|
—
|
%
|
Non utility
|
148,002
|
|
|
342,773
|
|
|
(194,771
|
)
|
|
(57
|
)%
|
Total Operating Revenues
|
$
|
11,682,950
|
|
|
$
|
11,889,570
|
|
|
$
|
(206,620
|
)
|
|
(2
|
)%
|
Delivered Volumes
|
|
|
|
|
|
|
|
Regulated Natural Gas (DTH)
|
|
|
|
|
|
|
|
Residential and Commercial
|
760,514
|
|
|
988,318
|
|
|
(227,804
|
)
|
|
(23
|
)%
|
Transportation and Interruptible
|
667,711
|
|
|
666,323
|
|
|
1,388
|
|
|
—
|
%
|
Total Delivered Volumes
|
1,428,225
|
|
|
1,654,641
|
|
|
(226,416
|
)
|
|
(14
|
)%
|
Heating Degree Days (Unofficial)
|
185
|
|
|
317
|
|
|
(132
|
)
|
|
(42
|
)%
|
Total operating revenues for the three months ended
June 30, 2019
, compared to the same period last year, declined primarily due to the lower non-utility activity combined with the offsetting effects of the rate increase and lower delivered volumes during the quarter. The Company placed new non-gas base rates into effect for natural gas service rendered on or after January 1, 2019, subject to refund. The new rates incorporated revenues related to SAVE Plan activities through December 2018, as well as recovery of higher costs and non-SAVE infrastructure additions since the last rate application. Total revenues have
RGC RESOURCES, INC. AND SUBSIDIARIES
been reduced by an estimate for potential refunds based on the SCC staff report and managements assessments. Net firm volume deliveries declined by 227,804 decatherms. After adjusting for WNA and the transfer of a large commercial customer to firm transportation, total residential and commercial volumes effectively declined by approximately 24,000 decatherms or more than 2%. Non-utility revenue declined as a significant customer had a temporary reduction in service needs during the quarter. Service levels have since returned to more normal levels. In addition, the prior year included a reserve of $326,486 associated with the estimated excess revenues billed to customers as a result of the reduction in the corporate federal income tax rate. No such reserve was recorded during the current quarter due to the implementation of new non-gas base rates.
See the Regulatory and Tax Reform section below for more information regarding the new non-gas base rates, provision for refund and the excess revenues related to the reduction in the corporate federal income tax rate.
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|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
|
|
2019
|
|
2018
|
|
Increase / (Decrease)
|
|
Percentage
|
Gas Utility Margin
|
|
|
|
|
|
|
|
Utility Revenues
|
$
|
11,534,948
|
|
|
$
|
11,546,797
|
|
|
$
|
(11,849
|
)
|
|
—
|
%
|
Cost of Gas
|
4,132,871
|
|
|
4,870,683
|
|
|
(737,812
|
)
|
|
(15
|
)%
|
Gas Utility Margin
|
$
|
7,402,077
|
|
|
$
|
6,676,114
|
|
|
$
|
725,963
|
|
|
11
|
%
|
Regulated natural gas margins from utility operations (total utility revenues less utility cost of gas) increased from the same period last year primarily as a result of the implementation of higher non-gas base rates as filed under the rate application with the SCC. SAVE revenues declined by $1,142,587 as all related SAVE activities through December 31, 2018 were incorporated into the new non-gas base rates effective January 1, 2019. As noted above, the SCC staff recommended a change in the proposed rate design of the non-gas rate increase between customer base charge and volumetric rates. In designing the rates submitted in the rate application, the Company included SAVE related revenues in the base charge component as the SAVE rider was previously reflected as a fixed fee on customers bills. As a result, the new rates implemented effective January 1 included a much larger allocation of the rate increase to the customer base charge. The SCC staff recommended in their report to significantly reduce the customer base charge rate and move it to the volumetric component of non-gas rates. Due to staff's position, the Company modified its rate refund assumptions in the current quarter, resulting in a significant reduction in customer base charge revenue and an increase in volumetric revenue. If the same rate refund factors had been applied in March, the accrued refund would have been less during the prior quarter, due to the change in the customer base charge vs volumetric components, and higher during the current quarter. As noted above, the prior year included a reserve of $326,486 related to excess revenues to be refunded to customers due to the reduction in the federal income tax rate.
The components of and the change in gas utility margin are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
2019
|
|
2018
|
|
Increase / (Decrease)
|
Customer Base Charge
|
$
|
2,616,903
|
|
|
$
|
3,130,911
|
|
|
$
|
(514,008
|
)
|
Carrying Cost
|
70,485
|
|
|
89,920
|
|
|
(19,435
|
)
|
SAVE Plan
|
96,483
|
|
|
1,239,070
|
|
|
(1,142,587
|
)
|
Volumetric
|
4,140,562
|
|
|
2,431,276
|
|
|
1,709,286
|
|
WNA
|
461,315
|
|
|
80,317
|
|
|
380,998
|
|
Other Gas Revenues
|
16,329
|
|
|
31,106
|
|
|
(14,777
|
)
|
Excess Revenue Refund
|
—
|
|
|
(326,486
|
)
|
|
326,486
|
|
Total
|
$
|
7,402,077
|
|
|
$
|
6,676,114
|
|
|
$
|
725,963
|
|
Operation and maintenance expenses increased by $613,168, or 22%, from the same period last year related to several factors including increased compensation costs, amortization of regulatory assets, corporate insurance costs, reduction in capitalized overheads and higher bad debt expense. Total compensation costs increased by $129,000 due to higher employment levels and wage increases. The Company began amortizing certain regulatory assets that are currently being recovered in the new non-gas base rates. Total amortization expense was $172,000. Corporate insurance costs increased by $96,000 due to increased liability limits and deductible coverage. Total capitalized overheads decreased by $136,000 due to lower capital expenditures
RGC RESOURCES, INC. AND SUBSIDIARIES
and the delayed timing of LNG production. Bad debt expense increased by $34,000 primarily due to the bankruptcy of a commercial account. Most of the remaining difference relates to scheduled maintenance at the LNG plant.
General taxes increased by $36,816, or 8%, associated with higher property and payroll taxes. Property taxes continue to increase corresponding to higher utility property balances related to ongoing infrastructure replacement, system reinforcements and customer growth.
Depreciation expense increased by $170,597, or 10%, on a corresponding increase in utility plant investment.
Equity in earnings of unconsolidated affiliate increased by $532,118, or more than triple last year, due to the extent of pipeline construction activities in the MVP. The corresponding earnings are primarily composed of allowance for funds used during construction ("AFUDC"). Additional information about the Company's investment in the MVP can be found under the Equity Investment in Mountain Valley Pipeline section below.
Other income (expense), net decreased by $42,824 primarily due to the adoption of ASU 2017-07,
Compensation - Retirement Benefits
, as discussed in Note 1, which resulted in the components of net periodic benefit costs other than service cost being presented outside of income from operations. As a result, the prior year amount has been adjusted retrospectively with the reclassification of a $30,633 net expense reduction from operations and maintenance to other income (expense) while the current period includes a net expense of less than $1,000 for these other net periodic benefit costs.
Interest expense increased by $342,106, or 59%, due to a 57% increase in total average debt outstanding between quarters. The higher borrowing levels derived from the ongoing investment in MVP, financing expenditures in support of Roanoke Gas' capital budget and higher interest rates on the Company's variable-rate debt. Total Midstream borrowing increased by more than $23 million while the average interest rate increased 43 basis points. Roanoke Gas' total borrowing increased by $10 million with an average interest rate increase of 10 basis points. As a result, the weighted-average effective interest rate on total Company debt increased from 3.97% in the third quarter of fiscal 2018 to 4.03% during the third quarter of fiscal 2019.
Income tax expense decreased by $102,545 due to a reduction in the federal income tax rate and the amortization of excess deferred taxes on the regulated operations of Roanoke Gas. The federal income tax rate declined from the 24.3% blended rate for fiscal 2018 to the statutory rate of 21% in fiscal 2019 with the combined state and federal rate declining from 28.84% to 25.74%. In fiscal 2018, Roanoke Gas revalued the net deferred tax liability of its regulated operations and recorded a regulatory liability, which is being amortized as a credit to tax expense over a 28-year period corresponding with a comparable reduction in revenues through reduced billings to customers. This results in no impact to net income as the reduction in income tax expense corresponds to a reduction in revenues. See Regulatory and Tax Reform section for more information.
Nine Months Ended
June 30, 2019
:
Net income increased by $1,630,061 for the nine months ended
June 30, 2019
, compared to the same period last year due to the implementation of a non-gas rate increase, equity in earnings from the investment in Mountain Valley Pipeline and lower income tax rates.
The tables below reflect operating revenues, volume activity and heating degree-days.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30,
|
|
|
|
|
|
2019
|
|
2018
|
|
Increase / (Decrease)
|
|
Percentage
|
Operating Revenues
|
|
|
|
|
|
|
|
Gas Utility
|
$
|
57,630,278
|
|
|
$
|
54,675,367
|
|
|
$
|
2,954,911
|
|
|
5
|
%
|
Non utility
|
544,378
|
|
|
888,227
|
|
|
(343,849
|
)
|
|
(39
|
)%
|
Total Operating Revenues
|
$
|
58,174,656
|
|
|
$
|
55,563,594
|
|
|
$
|
2,611,062
|
|
|
5
|
%
|
Delivered Volumes
|
|
|
|
|
|
|
|
Regulated Natural Gas (DTH)
|
|
|
|
|
|
|
|
Residential and Commercial
|
6,408,144
|
|
|
6,567,993
|
|
|
(159,849
|
)
|
|
(2
|
)%
|
Transportation and Interruptible
|
2,217,651
|
|
|
2,184,859
|
|
|
32,792
|
|
|
2
|
%
|
Total Delivered Volumes
|
8,625,795
|
|
|
8,752,852
|
|
|
(127,057
|
)
|
|
(1
|
)%
|
Heating Degree Days (Unofficial)
|
3,790
|
|
|
3,948
|
|
|
(158
|
)
|
|
(4
|
)%
|
RGC RESOURCES, INC. AND SUBSIDIARIES
Operating revenues for the nine months ended
June 30, 2019
increased over the same period last year due to the implementation of higher non-gas rates and higher gas costs. The Company placed new non-gas base rates into effect for natural gas service rendered on or after January 1, 2019, subject to refund. The new non-gas base rates were reflected in the Company's rate application with the SCC as filed in October 2018. The rates are subject to refund and the Company has revised its estimated refund based on on the SCC staff report and managements assessments regarding the final award. Residential and commercial deliveries declined by 159,849 decatherms based on weather that was 4% warmer than the same period last year. After adjusting for WNA and the transfer of a large commercial customer to firm transportation, total residential and commercial volumes actually reflect an increase of 94,000 decatherms, or more than 1%. The average commodity price of natural gas delivered during the first nine months of fiscal 2019 was approximately 5% per decatherm higher than the same period last year. Natural gas commodity prices spiked during December due to weather, but have since returned to lower levels. The prior year included a reserve of $1,147,829 associated with the estimated excess revenues billed to customers as a result of the reduction in the corporate federal income tax rate. The current fiscal period reflects a reserve of $523,881 as the accrual for excess revenues ended with the implementation of new non-gas base rates, which incorporated the reduction in the federal income tax rate. Non-utility revenue declined primarily due to reduced customer needs during the third quarter.
See the Regulatory and Tax Reform section below for more information regarding the non-gas rate application.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30,
|
|
|
|
|
|
2019
|
|
2018
|
|
Increase
|
|
Percentage
|
Gas Utility Margin
|
|
|
|
|
|
|
|
Utility Revenues
|
$
|
57,630,278
|
|
|
$
|
54,675,367
|
|
|
$
|
2,954,911
|
|
|
5
|
%
|
Cost of Gas
|
28,810,668
|
|
|
28,175,366
|
|
|
635,302
|
|
|
2
|
%
|
Gas Utility Margin
|
$
|
28,819,610
|
|
|
$
|
26,500,001
|
|
|
$
|
2,319,609
|
|
|
9
|
%
|
Regulated natural gas margins from utility operations increased from the same period last year for the same reason that margins increased for the quarter. Based on the proposed rate design changes submitted by the SCC staff in their report on the non-gas rate application, customer base charges and non-gas volumetric margins increased by $687,159 and $2,864,830, respectively, net of the estimated refund. SAVE revenues declined by $2,156,998 as all related SAVE activities through December 31, 2018 were incorporated into the new non-gas base rates. The reserve for excess revenues related to the reduction in federal income taxes declined by $623,948.
The components of and the change in gas utility margin are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30,
|
|
|
|
2019
|
|
2018
|
|
Increase / (Decrease)
|
Customer Base Charge
|
$
|
10,066,665
|
|
|
$
|
9,379,506
|
|
|
$
|
687,159
|
|
Carrying Cost
|
345,052
|
|
|
400,361
|
|
|
(55,309
|
)
|
SAVE Plan
|
1,327,020
|
|
|
3,484,018
|
|
|
(2,156,998
|
)
|
Volumetric
|
17,177,789
|
|
|
14,312,959
|
|
|
2,864,830
|
|
WNA
|
350,393
|
|
|
(43,448
|
)
|
|
393,841
|
|
Other Gas Revenues
|
76,572
|
|
|
114,434
|
|
|
(37,862
|
)
|
Excess Revenue Refund
|
(523,881
|
)
|
|
(1,147,829
|
)
|
|
623,948
|
|
Total
|
$
|
28,819,610
|
|
|
$
|
26,500,001
|
|
|
$
|
2,319,609
|
|
Operation and maintenance expenses increased by $1,132,618, or 12%, from the same period last year for many of the same reasons as reflected in the quarter: higher compensation costs, amortization of regulatory assets, corporate insurance costs, lower capitalized overheads and higher bad debt expense. Total compensation costs increased by $460,000 due to higher employment levels and wage increases. The Company began amortizing certain regulatory assets in January 2019 resulting in an additional $238,000 in expense. Corporate insurance expense increased by $96,000 due to higher premiums related to increased liability limits and higher deductible reserves. Capitalized overheads declined by $67,000 primarily due to timing of LNG production. Bad debt expense increased by $56,000 related to increased customer billings. The remaining increase relates to maintenance work at the LNG plant and other minor items.
RGC RESOURCES, INC. AND SUBSIDIARIES
General taxes increased by $127,862, or 9%, associated with higher property and payroll taxes. The increase in property taxes reflects the ongoing investment in the utility infrastructure of Roanoke Gas while the higher payroll taxes correspond to compensation activity.
Depreciation expense increased by $511,791, or 10%, on higher utility plant investment.
Equity in earnings of unconsolidated affiliate increased by $1,453,018, due to the significant increase in the investment in the MVP project.
Other income (expense), net increased by $148,322 primarily due to the revenue sharing incentive mechanism approved in 2018, partially offset by the reclassification of the components of net periodic benefit costs other than service cost from operations to a non-operating expense and timing of charitable contributions.
Interest expense increased by $805,706, or 44%, due to a 38% increase in total average debt outstanding and rising interest rates on the Company's variable-rate debt. Increased borrowing is attributable to the investment in MVP and funding of Roanoke Gas' capital budget. The weighted-average effective interest rate on total Company debt increased from 3.77% for the first nine months of fiscal 2018 to 3.96% for the same period in fiscal 2019.
Income tax expense declined by $485,831 due to a reduction in the federal income tax rate, the amortization of excess deferred taxes on the regulated operations of Roanoke Gas and the valuation adjustment to the deferred taxes of the unregulated operations in the prior year. The federal income tax rate declined from the 24.3% blended rate for fiscal 2018 to the statutory rate of 21% in fiscal 2019. As discussed above and in the Regulatory and Tax Reform section below, Roanoke Gas is amortizing the regulatory liability related to the excess deferred taxes on the regulated operations into income tax expense with a corresponding reduction in revenues. During the first quarter of fiscal 2018, Resources revalued the deferred taxes of its unregulated operations, which resulted in $208,000 direct charge to income tax expense.
Critical Accounting Policies and Estimates
The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and assumptions that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and management judgments. Actual results may differ significantly from these estimates and assumptions.
The Company considers an estimate to be critical if it is material to the financial statements and requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. The Company has recorded an estimate for refund related to the implementation of the new non-gas base rates effective January 1, 2019. This estimate reflects the adjustments proposed by the SCC staff in their report issued on June 28, 2019 as well as management's assessment of the likelihood of successfully rebutting certain SCC staff adjustments. As the process continues, management will continue to refine the estimate until a final order is issued.
The Company adopted ASU 2014-09,
Revenue from Contracts with Customers
, and subsequent guidance and amendments effective October 1, 2018. The adoption of the ASU did not have a significant effect on the Company's results of operations, financial position or cash flows as the new guidance resulted in essentially no change in the manner and timing in which the Company recognizes revenues. The primary operation of the Company is the sale and/or delivery of natural gas to customers (the performance obligation) based on SCC approved tariff rates (the transaction price). The Company recognizes revenue through billed and unbilled customer usage as natural gas is delivered. The Company also recognizes revenue through Alternative Revenue Programs, which are mechanisms authorized by the SCC that allow the Company to recognize or defer revenue independent of the collection from, or refund to, customers.
There have been no other changes to the critical accounting policies as reflected in the Company’s Annual Report on Form 10-K for the year ended September 30, 2018.
Asset Management
Roanoke Gas uses a third-party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the asset manager pays Roanoke Gas a monthly utilization fee. In accordance with an SCC order issued in 2018, a portion of the utilization fee is retained by the Company with the balance passed through to customers through reduced gas costs.
RGC RESOURCES, INC. AND SUBSIDIARIES
Equity Investment in Mountain Valley Pipeline
On October 1, 2015, the Company, through its wholly-owned subsidiary Midstream, entered into an agreement to become a 1% member in Mountain Valley Pipeline, LLC (the "LLC"). The purpose of the LLC is to construct and operate the MVP, a FERC regulated natural gas pipeline connecting Equitran's gathering and transmission system in northern West Virginia to the Transco interstate pipeline in south central Virginia.
Management believes the investment in the LLC will be beneficial for the Company, its shareholders and southwest Virginia. In addition to the potential returns from the investment in the LLC, Roanoke Gas will benefit from access to an additional source of natural gas to its distribution system. Currently, Roanoke Gas is served by two pipelines and an LNG peak shaving facility. Damage to or interruption in supply from any of these sources, especially during the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third pipeline would reduce the risk from such an event. In addition, the proposed pipeline path would provide the Company with a more economically feasible opportunity to provide natural gas service to previously unserved areas in southwest Virginia.
On October 13, 2017, FERC issued the MVP Certificate of Public Convenience and Necessity. Furthermore, since January 2018, FERC has issued several Notices to Proceed ("NTP"), which granted the LLC permission to begin construction activities. Since construction began, the LLC has encountered several challenges which have delayed the project, including weather issues, pipeline protesters and legal challenges to various federal and state permits resulting in stop orders and FERC intervention. Construction activities are proceeding with more than 80% of the project completed. Certain permits have been vacated or stayed, which currently prevents the LLC from working in stream crossings or wetlands. In addition, FERC issued a stop work order that directed all construction activity to cease within a 25-mile exclusion zone in and around the Jefferson National Forest. The LLC continues to work with all related regulatory entities and judicial bodies to resolve these issues. The LLC has indicated that the restrictions related to the stream crossings should be resolved this year and access granted to the Jefferson National Forest by next spring. Based on these time lines, the LLC managing partner has revised the projected in-service date to mid-2020.
As a result of the revised time line for completing the MVP as noted above, the LLC revised the estimated project cost to between $4.8 and $5.0 billion from the previous estimate of $4.6 billion with Midstream's estimated cash investment expected to increase to nearly $50 million. Furthermore, the delays in completing the project combined with the increased costs will reduce the corresponding return on investment, absent a regulatory action, which could provide for the recovery of these higher costs.
Midstream issued two intermediate term notes in the amount of $24 million in June 2019 to finance a portion of the investment in MVP. The remainder of the financing for the project will be from the notes under the non-revolving credit agreement with a total capacity of $26 million with $11.3 million outstanding at June 30, 2019.
Most of the current earnings from the investment in MVP relate to AFUDC income generated by the deployment of capital in the design, engineering, materials procurement, project management and construction of the pipeline. AFUDC is an accounting method whereby the costs of debt and equity funds used to finance facility infrastructure are credited to income and charged to the cost of the project. As investment in the MVP grows, so will the amount of AFUDC recognized until the pipeline is placed in service. Earnings after the pipeline becomes operational will be derived from the fees charged for transporting natural gas through the pipeline.
In 2018, Midstream became a participant in the MVP Southgate project ("Southgate"), to construct a 70-mile pipeline extending from the MVP mainline at the Transco interconnect in Virginia to delivery points in North Carolina. Midstream is a less than 1% investor in the Southgate project and, based on current project cost estimates, will invest between $1.8 million and $2.5 million toward the project. Midstream's participation in the Southgate project is for investment purposes only. The Southgate in-service date is currently targeted for the end of calendar 2020.
Regulatory and Tax Reform
On October 10, 2018, Roanoke Gas filed a general rate case application requesting an annual increase in customer non-gas base rates of approximately $10.5 million. This application incorporates into the non-gas base rates the impact of tax reform, non-SAVE utility plant investment, increased operating costs, recovery of regulatory assets associated with eligible safety activity costs ("ESAC") and SAVE plan revenues previously billed through the SAVE rider. The new non-gas base rates were placed into effect for gas service rendered on or after January 1, 2019, subject to refund, pending audit by SCC staff, hearing and final order by the SCC.
RGC RESOURCES, INC. AND SUBSIDIARIES
On June 28, 2019, the SCC staff issued their report and recommendations related to the rate application. Management has reviewed the SCC staff's report and plans to submit rebuttal testimony to certain proposed adjustments included in staff's report for the hearing scheduled for August 14, 2019. The major differences with staff's report that management plans to contest include the proposed return on equity, the exclusion of certain infrastructure items from rate base, changes in customer class rate design and the exclusion of a portion of the regulatory assets associated with the ESAC costs. Management has completed a review of each of the SCC staff's recommended adjustments including those that the Company will contest and has reflected their assessments, including revisions to the accrued estimated refund in the consolidated financial statements. Sometime after the hearing, the hearing examiner will issue his report and the SCC Commissioners will make a final determination on the rate application and issue a final order. A final order is not expected until late first quarter or early second quarter of fiscal 2020. As more information becomes available during this process, the Company will continue to refine its estimates and assumptions reflected in the financial statements until such time as the SCC issues its final order and estimates are finalized.
Since its last rate case, Roanoke Gas has deferred ESAC costs attributable to compliance and safety related expenses. These expenses were above and beyond a base line for those costs previously provided for in non-gas base rates and have been included in the current rate application for recovery over a five-year period. As noted above, the SCC staff report recommended excluding approximately $400,000 of these costs from rate recovery. The Company has completed an assessment of the likelihood of a successful challenge to the SCC's position on these assets, which have been reflected in the financial statements. If the SCC ultimately determines to exclude these assets from rate recovery in its final order, then a portion of these assets would be written down to the balance allowed to be recovered.
As noted above, the general rate case application incorporated the effects of tax reform, which reduced the federal tax rate for the Company from 34% to 21%. Roanoke Gas recorded two regulatory liabilities to account for this change in the federal tax rate. The first regulatory liability related to the excess deferred taxes associated with the regulated operations of Roanoke Gas. As Roanoke Gas had a net deferred tax liability, the reduction in the federal tax rate required the revaluation of these excess deferred income taxes to the 21% rate at which the deferred taxes are expected to reverse. The excess net deferred tax liability for Roanoke Gas' regulated operations was transferred to a regulatory liability, while the revaluation of excess deferred taxes on the unregulated operations of the Company were flowed into income tax expense in the first quarter of fiscal 2018. A majority of the regulatory liability for excess deferred taxes was attributable to accelerated tax depreciation related to utility property. In order to comply with the IRS normalization rules, these excess deferred income taxes must be flowed back to customers and through tax expense based on the average remaining life of the corresponding assets, which approximates 28 years. As of June 30, 2019, Roanoke Gas had approximately $11,100,000 in both current and non-current portions of the net regulatory liability.
The second regulatory liability relates to the excess revenues collected from customers. The non-gas base rates used since the passage of the TCJA in December 2017 through December 2018 were derived from a 34% federal tax rate. As a result, the Company over-recovered from its customers the difference between the federal tax rate at 34% and the 24.3% blended rate in fiscal 2018 and 21% in fiscal 2019. To comply with an SCC directive issued in January 2018, Roanoke Gas recorded a refund for the excess revenues collected in fiscal 2018 and the first quarter of fiscal 2019.
Beginning with the implementation of the new non-gas base rates in January 2019, Roanoke Gas began returning the excess deferred income taxes over the 28-year period and the excess revenues to customers over a 12-month period. The estimated refund amounts for both the excess deferred taxes and the excess revenues associated with the reduction in the federal income tax rate were subject to review and adjustment by the SCC, which was done by its staff in connection with its audit of the rate case application. The SCC staff report agreed with the refund amounts reflected in the Company's financial statements, and assuming no changes during the hearing or by the Commissioners, these amounts will be reflected in the final order.
The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. The original SAVE Plan was designed to facilitate the accelerated replacement of aging natural gas pipe by providing a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. Since the implementation and approval of the original SAVE Plan in 2012, the Company has modified, amended or updated it each year to incorporate various qualifying projects. In May 2019, the Company filed its most recent SAVE Plan and Rider, which continues the focus on the ongoing replacement of pre-1973 plastic pipe and the replacement of a natural gas transfer station. If approved, the new SAVE Plan Rider will be effective in October 2019 with SAVE rates designed to collect approximately $1.2 million in annual revenues, an increase from the approximate $500,000 in annual revenues under the current SAVE rates. With the inclusion of all previous SAVE investment through December 31, 2018 into the rate application, the current SAVE Plan Rider reflects only the recovery of qualifying SAVE Plan investments made since the beginning of January 2019. In addition, the SAVE application includes a request to refund approximately $500,000 in SAVE revenue over-collections from 2018, which resulted primarily from the effect of the reduction in income tax rates.
RGC RESOURCES, INC. AND SUBSIDIARIES
As noted above, Roanoke Gas contracts with a third party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for the right to utilize the excess capacities of the transportation and storage rights, the asset manager credits Roanoke Gas monthly for an amount referred to as a utilization fee. In June 2018, the SCC issued an order, retroactive to April 1, 2018, approving implementation of an incentive mechanism, whereby the Company shares the utilization fee with its customers. Under the incentive mechanism beginning April 1 each year, customers receive the initial $700,000 of the utilization fee collected through reduced gas costs, and thereafter, every additional dollar received during the annual period is split 25% to the Company and 75% to its customers.
On February 7, 2019, the SCC issued a final order granting a Certificate of Public Convenience and Necessity ("CPCN") to furnish gas service to all of Franklin County. If the Company does not furnish gas service to the area so designated within five years of the date of the order, the CPCN granting authority to serve Franklin County will be terminated.
On June 14, 2019, Roanoke Gas filed an application with the SCC for authority to issue up to $40 million in short-term debt and up to $100 million of long-term debt or common equity. Roanoke Gas' current financing authorization expires on September 30, 2019. The new authorization request is for 5 years ending on September 30, 2024.
Roanoke Gas' provision for depreciation is computed principally based on composite rates determined by depreciation studies. These depreciation studies are required to be performed on the regulated utility assets of Roanoke Gas every five years. The last depreciation study was completed and implemented in fiscal 2014. On June 11, 2019, Roanoke Gas submitted it's current depreciation study, which incorporates all of the new and replacement infrastructure and equipment placed in service since the last study. The depreciation study is subject to administrative review, and if approved, these new rates will result in a small reduction in depreciation expense. The Company expects to implement the new depreciation rates in its fiscal 2019 fourth quarter.
Capital Resources and Liquidity
Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are the funding of its utility plant capital projects, investment in the MVP, the seasonal funding of its natural gas inventories and accounts receivable and the payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, long-term debt and equity capital.
Cash and cash equivalents increased by $990,934 for the nine-month period ended June 30, 2019, compared to a $1,130,862 increase for the same period last year. The following table summarizes the sources and uses of cash:
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30,
|
|
2019
|
|
2018
|
Cash Flow Summary
|
|
|
|
Net cash provided by operating activities
|
$
|
16,586,517
|
|
|
$
|
13,859,063
|
|
Net cash used in investing activities
|
(33,296,103
|
)
|
|
(21,296,642
|
)
|
Net cash provided by financing activities
|
17,700,520
|
|
|
8,568,441
|
|
Increase in cash and cash equivalents
|
$
|
990,934
|
|
|
$
|
1,130,862
|
|
The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year as well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer collections, contribute to working capital levels and the related cash flows. Generally, operating cash flows are positive during the second and third quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows generally decrease due to increases in natural gas storage levels, rising customer receivable balances and construction activity.
Cash flow provided by operations is primarily driven by net income, depreciation and reductions in natural gas storage inventory during the first nine months of the fiscal year. Cash flow from operating activities increased over the same period last year by $2,727,454 primarily related to higher over-collections of gas costs, lower gas in storage balances and depreciation offset by an increase in accounts receivable and reductions in regulatory liabilities and deferred taxes. Although net income increased by $1.6 million, it did not significantly impact cash flow as much of the increase in net income was attributable to the non-cash equity in earnings from the investment in MVP. Over-collections of gas cost increased by more than $3.5 million over the same period last year. Gas prices spiked in December and futures prices at the time indicated that natural gas commodity prices would remain at an elevated level during the winter months. Based on this information, the Company filed its quarterly PGA adjustment reflecting higher prices; however, commodity prices returned to lower levels during the second
RGC RESOURCES, INC. AND SUBSIDIARIES
and third fiscal quarters resulting in the increase in over-collections. The combination of lower gas prices and lower storage levels contributed $832,000 to the increase in operating cash. Accounts receivable balances increased by $920,000 over the same period last year primarily as a result of the implementation of new non-gas rates and the inclusion of the WNA receivable. Regulatory liabilities and deferred taxes increased to a lesser degree during the current year, as the amortization of the regulatory liabilities established last year due to tax reform partially offset the current year increase related to the estimated refund associated with the implementation of new non-gas rates. A summary of the cash provided by operations is provided below: