Bruce Warner, CPA, CDP, CFF

Gas Pipeline Pricing Evolution – MeetingThe Challenges of Modern Markets

Gas pipeline prices (rates or tolls) in the United States have evolved over the time since passage of the Natural Gas Act (NGA) in 1938[i] from a strict cost-plus-profit model to a more indirectly regulated regime today. This article discusses past and present pricing alternatives and the ramifications of a number of current risks facing pipeline developers and their customers.

The first (and still used) cost-plus pricing models determined prices by employing “cost of service” principles. The resulting prices are either known as “Stated Rates” or “Cost of Service Rates.” Stated Rates remain fixed in a pipeline’s base tariff between rate change dates, such as the dates that general rate changes are implemented.  Cost of Service rates vary periodically between the system-wide rate change dates as the inputs into the cost of service formula change.

Stated Rates please regulators because the pipeline owner experiences incentives to reduce costs as a way to improve profits, thereby also encouraging rate stability. The cost reductions may be passed on to shippers if rates are reduced. The gas pipeline industry today faces claims by gas producer interests, some shippers and some state regulators that the efficiency incentives under Stated Rates have been too strong. Some of those parties argue that the NGA should be changed in a way that successful rate challenges would occasion relief back to the date of a rate complaint, rather than being effective only prospectively as under current law.

Costs of Service rates usually fall flat with regulators today because they tend to guarantee profit results and do not provide substantial efficiency incentives. However, Cost of Service formula rates still exist under specific contract rates with shippers because of the shippers’ desire to not pay more than actual costs. Cost of Service rates, depending on how they are defined, may create extra administrative and audit burdens. However, in some situations Cost of Service rates can be useful as a means of resolving disputes between a pipeline and its customers.

Cost-Plus Pricing Fundamentals

For companies that calculate rates under cost-plus pricing, one of the most important and contentious cost elements is the cost of common equity. Cost of service, or the revenue requirement of the utility, includes operating expenses, taxes, return on rate base including the cost of debt and equity financing, depreciation, and a reduction for incidental revenues.

To calculate the return on rate base, it is necessary to first calculate rate base. This item represents the net current investment in utility facilities that has been financed by investors. Rate base includes the cost of property, reduced by accumulated depreciation and deferred income taxes. Rate base also includes operating capital, such as materials and supplies inventories and prepayments.

The weighted average cost of debt and equity, or return on rate base, includes: (1) the sum of the cost of debt multiplied by the percentage of the total capital structure that is financed by debt, and (2) the cost of each source of equity financing multiplied by the percentage of the total capital structure that is financed by each equity source. Once the weighted cost of each financing source is calculated, the costs of all the financing sources are summed to derive the total weighted average cost of capital. The cost of common equity is generally the subject of much dispute and litigation, the details of which are beyond the scope of this article except to say that some new pricing methods may in part have the advantage of bypassing such disputes.

The Importance of Perceived Gas Pipeline Market Power

The U. S. federal regulatory regime rests on the regulatory importance of perceived (or actual) gas pipeline market power[ii].  At the industry’s inception the concept of cost-plus pricing reflected the idea that gas pipelines are essential utilities to the public, costly to duplicate, and have the potential to exercise market power; i. e., gas pipelines if left unrestrained by regulation could presumably exercise market power by charging rates above the cost of service rate and/or competitive rate.

The Evolution of Market-Oriented Pricing Strategies

Market-oriented strategies may be employed to develop successful gas pipeline projects under regulatory policy changes that occurred in 1996 and 1999.[iii] During those years, the FERC issued policy statements that enhanced the competitive landscape for new natural gas pipelines and for expansions of existing pipelines.

1996 Developments –

At the urging of the pipeline industry, in early 1996 the FERC issued its Statement of Policy on Alternatives to Traditional Cost-of-Service Ratemaking and its companion Policy on Regulation of Negotiated Services of Natural Gas Pipelines (1996 Policy Statement)[iv]. These documents became important as permitting indirectly market responsive pricing for pipeline transportation through a price-capped rate regime.

The 1996 Policy Statement introduced two new concepts for both the pricing of new gas pipeline infrastructure and for fostering markets for ongoing gas storage and transportation transactions. Under the first concept, “negotiated rates,” the pipeline and its customers by agreement may deviate from normal cost-plus tariff pricing. As an example, variations from the usually required straight-fixed variable pricing method (“SFV”)[v] are permitted. In addition, the pipeline may propose innovative cost of service calculation methods, such as rate levelization plans.[vi]

Negotiated rates are attractive to shippers because they allow better matching of cost calculations by service period to ability to pay, and such plans can result in a fixed rate for a number of years that is not subject to rate case disputes. For example, a rate levelization regime may benefit shippers by providing significantly lower initial prices than the traditional cost of service and declining rate base methodology (Traditional Rate Method).[vii] (Indeed, some projects very likely won’t get built today at all unless a levelized price is used, particularly because the FERC no longer permits existing shippers to subsidize expansions, as further discussed below.)

The second important idea in the 1996 Policy Statement is the concept of a “recourse rate.” As a predicate to permitting flexible, negotiated rates, the FERC required a calculation of a ceiling price to serve as a constraint on potential monopoly pricing power. Recourse rates for pipeline infrastructure additions have devolved generally into a price that is established under the Traditional Rate Method.[viii] The FERC required that such recourse rates would always be offered as an alternative to negotiated prices. The Commission ruled that costs and revenues related to negotiated services must be separately identified in pipeline records to facilitate the review of the effects of such services during general rate case proceedings.

When a rate case arises, the pipeline must be prepared to assume the full risk of its negotiated services without seeking discount adjustments in establishing the billing determinant levels used to calculate prices. Cost allocations among the pipeline’s various services must be calculated as though the negotiated service shippers are paying maximum recourse rates. As a result of these rules, entering into negotiated transactions exposes the pipeline to the full risk of each transaction, but with pricing tools needed to meet a broader market demand and the potential for improved earnings due to lighter regulation over price.

1999 Developments –

Pricing principles continued to evolve with the issuance of an order that departed dramatically from past pricing principles. Prior to 1999, a debate raged in the industry regarding which expansion project costs would be rolled-in, or averaged into, existing rates and which projects involve costs so significant that they should be priced on a stand-alone basis, which is referred to as incremental pricing.[ix]

Under the new pricing policy[x], the Commission stated:

“The threshold requirement in establishing the public convenience and necessity for existing pipelines proposing an expansion project is that the pipeline must be prepared to financially support the project without relying on subsidization from its existing customers.”

The Commission explained that the requirement for projects to be able to stand on their own without subsidies “…recognizes that a policy of incrementally pricing facilities sends the proper price signals to the market …the market will then decide whether a project is financially viable.” The FERC set in stone the principle that existing customers should not have to subsidize a project that does not serve them. This no-subsidy principle therefore made it more difficult to build new projects in competition with other more depreciated pipeline systems without the tools available from the newer, more creative pricing methods. However, rolled-in pricing was still permitted in certain circumstances, such as when a project would reduce existing rates or if the project is constructed solely to enhance system flexibility or reliability.

Economic and Regulatory Approaches in a New Environment

The Environment Today –

Significant economic, environmental and political pressures surround new infrastructure projects. These issues confront all stakeholders: governmental agencies, project sponsors, debt holders and gas consumers. With the disappearance of formal public convenience and necessity hearings in most regulatory jurisdictions, regulators increasingly rely on the confluence of market forces to decide which projects should be built. Today market forces are used to: (1) select among potential project sponsors, (2) allocate capacity among shippers and (3) create contractual means to mitigate project risks (such as the risk of a cost overrun or the risk of shipper default). Whether project sponsors build a project generally no longer is dependent on regulatory approval, rather sponsors are at risk for their investment decisions.

Since the market decides those matters, then logically market forces in many instances should also be permitted to select the means of pricing the projects, both over the short-term and long-term. However, to this point public policy has not been resolved in favor of unbridled market-based pricing of all gas transmission projects due to a strong lingering concern that gas pipelines are uniquely invested in the public welfare, are costly to duplicate and good alternatives to pipeline transportation do not exist in all geographic and product markets. Nevertheless, the FERC’s current incremental pricing and negotiated rates policies permit more market-responsive prices than were possible in prior years.

Blending Regulatory and Negotiated Rate Options –

Negotiated rates can be viewed as economically efficient because they bring a willing buyer and willing seller together in an environment where potential market power is constrained. In practice, negotiated prices are not a “one size fits all” proposition. A key dynamic of such prices is how the parties choose to deal with the length of the pricing arrangement, considering particularly that (for projects to secure debt financing) a degree of certainty usually must be achieved over contract terms of 10 or 15 years, or more. One issue that hasn’t, in my opinion, been dealt with completely yet by regulators or project participants is what will happen to the rates, depreciation recovery and ultimate project success once existing negotiated rate projects ramp off of their existing contracts. Today’s typical negotiated contracts with their 10 or 15 year contract terms are significantly shorter than the probable life of the facilities and related gas supplies. Project sponsors can’t be assured that they will be able to negotiate acceptable prices again with a new group of shippers. If such newly negotiated arrangements fail, then a host of regulatory issues could arise since it is not at all clear what rate base will then be available to the project sponsor under then existing regulatory principles.

We might ask, given the negotiated rate option’s availability, is there still a role for cost-plus pricing? Yes, there is for several reasons. First, the pipeline must establish initial rates for at least its interruptible services and re-justify or change those rates within three years of the inception of services under traditional rate principles. Second, a pipeline may have a mix of traditional services and other negotiated services. Third, the recourse price must be calculated under traditional pricing to establish a cost ceiling for comparison to negotiated prices, since the pipeline may not charge base tariff rates above the cost ceiling.

A number of variations in the methods that blend the best features of regulation and negotiation are possible and available to meet the concerns of all stakeholders over the entire life of the project. Such blending is probably under-used today and would often be desirable. For example, customers may have concerns about certain elements of the cost of service, such as concerns regarding potential unjust earnings that could occur with economic changes over a long time period, resulting in stale cost inputs such as an outdated return on equity. On the other hand, a project sponsor may need to be protected against a change to the basic project pricing formula that may harm the recovery of the expected returns over the life of the facilities, such as could occur with an interim switch from the levelized method to the traditional rate method[xi], or due to an unexpected, hypothetical regulatory rate base that may evolve if the project sponsor is forced to revert to traditional regulatory pricing. If more use were made of blended regulatory and negotiated pricing arrangements, conceivably very long-term arrangements could be set that would both assure all parties of reasonable outcomes and avoid unnecessary regulatory disputes.

Other Considerations in Managing Project Risks –

Project sponsors and project participants would be well advised to consider in their long-term strategic and financial plans strategies and changes that will be necessary after the initial contracts to adapt to changing market, supply and regulatory conditions. For example, an under-appreciated need relates to setting a long-run strategy to depreciate and recover project costs. Long-term depreciation policies can dramatically affect a variety of important financial results, such as financial statement profitability, the amount of property taxes that may be paid by the project, the timing of cash flows, and in sum project returns.

NOTES

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[i] As explained by the Energy Information Administration on its web site, “… the Natural Gas Act (NGA) of 1938 was the first instance of direct Federal regulation of the natural gas industry. Concern about the exercise of market power by interstate pipeline companies prompted the passage of the NGA. That law gave the Federal Power Commission (FPC) (subsequently the Federal Energy Regulatory Commission (FERC)) the authority to set “just and reasonable rates” for the transmission or sale of natural gas in interstate commerce.”

[ii] The potential market power of owners of gas pipeline and storage projects has historically been restrained through cost-based pricing requirements implemented through the regulations pertinent to rate cases and other NGA Section 4 rate filings. Other constraints have occurred at the certification stage, such as through regulation of initial rates, implementing procedures for processing complaints, evaluating the impacts of projects on competitors and other stakeholders and through optional certificate rules. In recent years the methods used by FERC to review potential market power and to prevent its perceived ill effects have been refined through new policy statements, orders and regulations, such as Orders 436 and 500, et. al. Additional legislation, such as the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005, resulted in further extensions and elaboration of such energy policies.

[iii] Direct development of market-based rates for certain projects in competitive markets, such as for storage projects or in specific competitive gas transmission markets, is beyond the scope of this discussion. This article also does not discuss regulatory techniques used in other industries, such as price indexing employed for oil pipelines, because such approaches have not yet been applied by FERC to gas pipelines.

[iv] See 74 FERC ¶ 61,076 (1996).

[v] SFV prices mean charging fixed daily or monthly prices that include all pipeline costs, except costs that vary with throughput. Variable costs under this method are billed as gas volumes move through the pipeline system.

[vi] Rate levelization plans are intended to produce rates that remain stable throughout the terms of shipper contracts through some form of cost averaging. For example, a level rate may be calculated by changing the

timing of recovery of returns on investment or by modifying the timing of recovery of depreciation. Rate levelization plans are generally developed with the intent that the net present value of each particular project is the same as under the Traditional Rate Method, discussed below. The FERC has not defined a required levelization program in those instances where level rates are developed. Rate levelization plans that include straight-line depreciation may produce poor earnings in some years as a function of the way levelized prices are computed.

[vii] Under the Traditional Rate Method, prices, or rates, are calculated based on a declining rate base over the pipeline’s life and assuming the straight-line depreciation method. Assuming the absence of significant ongoing capital expenditures, rates under this method will tend to be the highest at the inception of service and will decline steadily thereafter.

[viii] To ensure that the recourse rate is not unduly restrictive, pipelines in certificate proceedings typically seek to calculate recourse rates under return and depreciation assumptions that make the negotiated price more attractive than the recourse rate.

[ix] Under the former pricing policy, the Commission applied a presumption in favor of rolled-in rates (rolling-in the expansion costs with pre-existing facilities’ costs) when the cost impact of the new facilities would result in a rate impact on existing customers of not more than five percent, and some system benefits would occur. In those instances, existing customers generally would bear these rate increases without being allowed to adjust their contract volumes.

[x] Certification of New Interstate Natural Gas Pipeline Facilities (Policy Statement) at 88 FERC ¶ 61,277.

[xi] Such a switch has been advocated by FERC Staff in a number of gas pipeline rate proceedings, creating very difficult issues for some of the parties.

Energy entrepreneurs are acquainted with the economic importance of Federal income tax incentives that promote the development of energy resources and infrastructure. Tax incentives include tax credits, bonus depreciation allowances[i] and favorable expensing rules for intangible drilling costs. 

Energy-related tax incentives offered by the Government target a variety of goals. Our nation has focused, albeit sporadically, on becoming more energy self-sufficient since the oil cartel-created shortages of the 1970s. People alive at that time recall waiting in long lines for gasoline. Conservation measures included neither running public fountains nor lighting Christmas lights. As a new employee in a gas pipeline in the 1970s, I heard Denver-based consultants paint a picture of ever increasing natural gas prices related to projected natural gas supply shortages. Natural gas was trading at very high prices (about $5 per MCF in Canada) in the early 1980s, and as a result plans were being made to construct an Alaska to Continental U. S natural gas line. That project ultimately was cancelled as tight natural gas supply conditions abated.

In large measure past tax incentives arguably have been successful in stimulating a favorable supply response. One poignant example is the effectiveness of the Internal Revenue Code §29 credit related to coal seam gas[ii] that stimulated a new technology of production. As a result of this and other factors, natural gas surpluses arose for most of the ensuing years. Other important changes included the impacts of gas and electricity deregulation, changes in demand for gas powered electric generation and technological improvements such as  horizontal drilling and fracturing formations that provided the ability to produce natural gas from shale gas plays.

Political events and the cycles of economic growth and recession have driven the emergence of new economic stimulus and environmental laws. Recently, climate change goals and a financial meltdown have taken the forefront of policy debates.  In spite of the partial success of past energy initiatives, as we begin the Obama years our nation finds itself in a quandary: How do we meet today’s environmental objectives and simultaneously promote economic development during a time of financial insecurity and slackening demand? An important consideration is that, although many of us would like to see “green power” technologies succeed, the fact is that today only roughly 3 percent of electricity (excluding hydro power from total resources) is generated from renewable power contributors.[iii]  In addition, many well known technological and logistical challenges remain, such as a shortage of transmission infrastructure for wind power and the present status of nascent carbon capture technology. In such an environment policy makers strive to be creative.  As far as tax policy is concerned, the government’s most recent economic stimulus package evinced creativity to promote “green energy” beyond past measures.

This article provides a summary of and comments on an important tax program that is targeted to both stimulate new near term “green energy” resources and the economy. The program involves cutting a check to energy project developers, rather than the alternative of permitting tax credits on their income tax returns. The program permits developers tax depreciation amounts over the life of these projects that exceeds out-of-pocket investments as discussed below, thus providing both a cash flow benefit and governmental financial subsidy. The incentives are intended to fill the gap temporarily created by diminished investor demand for the purchase of syndicated income tax credits. 

What is “The Deal” and Who is Eligible?

Section 1603 of the American Recovery and Reinvestment Tax Act of 2009 provides for optional cash payments, instead of tax credits, for eligible “green energy” property used in a trade or business or for the production of income. The payments apply to certain property placed in service during 2009 or 2010, or under some conditions in later years. The payments are equal to either 10% or 30% of the tax basis of the property, depending on the type of property. Payments will be made within 60 days of the later of the date the property is placed in service or a complete application claiming a payment is filed. Those who elect to receive the cash payments as a result also elect to forego otherwise available tax credits (production or investment credits) under Sections 45 and 48 of the Internal Revenue Code (Code). They also must agree to the terms and conditions of the Section 1603 program. To be eligible to receive payments, an application must be filed as described below.

To be eligible to receive cash payments, any applicant must be the owner or lessee of the property and must have placed the property in service. The cash payments don’t apply to non-business energy property and to residential energy efficient property as set forth in Sections 25C and 25D of the Code.  The payments can’t be claimed by governments, charitable organizations, clean energy bondholders, or cooperative electric companies. The payments also can’t be claimed by any direct or indirect partner (or other holder of an equity or profits interest) which is an organization described in the preceding sentence, unless this person only owns an interest in the applicant through a taxable C corporation.  Real estate investment trusts and Code §1381 (a) cooperatives are not pass-thru entities for this purpose. 

What Property Qualifies for Cash Payments?

Regardless of when construction begins, the property must be placed in service between January 1, 2009 and December 31, 2010, or alternatively construction must have begun in 2009 or 2010 and the property must be in service before a credit termination date (either January 1 of 2013, 2014 or 2017, depending on the type of property).  Thirty percent payments apply to large wind, biomass facility, geothermal under Code §45, landfill gas, trash facility, hydropower facility, marine & hydrokinetic facility, solar facility, fuel cells and small wind projects. Ten percent payments apply to geothermal under Code §48, microturbine, combined heat & power and geothermal heat pump projects. For fuel cells the maximum payment can’t exceed $1,500 for each KW of capacity, and for microturbines the maximum is $200 for each KW of capacity. Under this program expansions of existing eligible property may qualify for the cash payments.

Regarding the eligibility requirement that construction must have begun in 2009 or 2010 and if the facilities are to be completed later, the standard may be met only by conducting actual physical construction work of a significant nature on the project. The standard is not met by preliminary activities such as planning, designing, securing financing, exploring, clearing a site, test drilling to determine soil condition or excavation to change the contour of land. However, if the facilities involve modular construction at an off-site location the standard is met based on applying the principles referred to previously at the off-site location.  If the project is to be constructed by a third party under a contract, the contract must be binding and enforceable under State law as defined by several conditions of the program. The rules provide a safe harbor permitting the construction-must-have-begun standard to be met if the applicant has incurred or paid more than 5 percent of the cost of the property, excluding the cost of the preliminary activities described above.

Where the facility includes multiple units of property, such as a wind turbine farm, the owner of the multiple units may elect to treat the units and any control system that serves all units as a single unit property for purposes of determining the beginning of construction and the date the property is placed in service.  In such a case, failure to complete the entire project will not preclude receipt of payments for those components of the project that were completed within the deadlines of the Section 1603 payment program.

Where property, such as solar energy or fuel cell property, is installed on other property like a building or truck only the property described in Code §48 is eligible for the payment. Property used predominately outside the United States is not eligible. The original use of the property must begin with the applicant, but construction consisting of not more than 20 percent of used parts will not disqualify the eligibility of the property. 

How Can I Apply?

Applications are available at www.treasury.gov/recovery.  You must wait to submit an application until the property is in service if construction is completed in 2009 or 2010, but you may submit an application if the property is under construction in 2009 or 2010 and the project will be placed in service in later years. All applications must be received no later than October 1, 2011. For applications related to property under construction, supplemental information to verify completion must be submitted within 90 days after the property is placed in service.

Other application requirements include the applicant’s Data Universal Numbering System (DUNS) number which may be requested at no cost at 1-866-705-5711. You must also register with the Central Contractor Registration Service at www.ccr.gov/startregistration.aspx.

Applicants for the payments must submit required documentation demonstrating the eligibility of the property, that it has been placed in service, or if placed in service after 2010 that construction began in 2009 or 2010.  Examples of the documentation required to demonstrate eligibility include final engineering design documents certified by a professional engineer, documentation of nameplate capacity that meets required minimums or maximums, documentation of meeting efficiency requirements, and for hydropower projects evidence of a Federal Energy Regulatory Commission certification and license.

Documentation to demonstrate that the property has been placed in service includes a commissioning report by the project engineer, equipment vendor or independent third party certifying that the equipment has been installed, tested and is ready and capable of its intended use. If the property is connected to a utility the documents must demonstrate that the interconnection agreement is in effect. Documentation of the project being under construction but not yet in service must include paid invoices or other financial documents demonstrating that significant physical work has begun or the project meets the safe harbor test.

Other Requirements

The income tax basis of the property upon which the cash payments are calculated is determined under the general rules for determining the basis of property for depreciation purposes under the Code and IRS regulations. No payments will be made related to property expensed all at once under Code §179, or if intangible drilling and development expenses (IDD) will be deducted currently by the applicant. However, IDD costs that will be depreciated or amortized are eligible. Applicants must submit documentation supporting the claimed cost basis of the property, including a detailed breakdown of all costs and, for properties with a cost of over $500,000, an independent accountant’s certification attesting to the accuracy of the claimed costs.

While these cash payments are not taxable income in the gross income of the applicant, the basis of the property is reduced by only 50 percent of the payment. This means that available tax depreciation allowances will be reduced only partially (either by 15 percent or by 5 percent, depending on the type of property) as a result of the cash payments (either 30 percent or 10 percent, depending on the type of property); thus, the depreciation permitted on the property will exceed the investor’s actual net cost of the facilities. This is a very favorable provision considering that the property may also be eligible for 50 percent bonus income tax depreciation. The cash payments must be normalized under the provisions of former Code §46(f) applicable to the computation of accumulated deferred income taxes for utilities.

Leasing transfers from a lessor to a lessee do not annul eligibility for the cash payments as long as several requirements are met. First, both the lessor and lessee must be eligible parties to receive the payments. Second, the lessor must agree to transfer its rights to the lessee by waiving its right to the payments and to production or investment tax credits. Third, the basis for computation of the payments must use an independently assessed fair market value of the property on the date of transfer under the Code and the regulations governing elections to allow lessees to receive energy tax credits. Fourth, the lessee must agree to include ratably in its gross taxable income 50 percent of the payments as a recapture of income over a five year period.

Sale and leaseback transactions are permitted.  In that case, the lessee must be the person who originally put the property in service, and the transaction must occur within three months after the project in service date.

If an applicant disposes of the property to an unqualified entity, or if the property ceases to be eligible for the cash payment, or permanent cessation of production occurs during the first five years of service, the cash payments are recaptured (required to be put into gross taxable income) ratably over that time. In other words, 80 percent of the credit amount would be recaptured if the property is sold during the second year of service, 60 percent if this occurs during the third year of service and so forth.

Conclusion

Project developers likely will be attracted to this new government program because significant energy tax incentives can be monetized early in the project life without having to “syndicate” the transaction, such as was done by the Williams Coal Seam Gas Royalty Trust, as is discussed herein in the endnotes. The cash payments will reduce the effective cost of the eligible “green energy” projects, though the concept potentially tends to encourage less efficient projects.  Project developers should seek to understand these rules thoroughly and to plan carefully to meet the requirements of the law. If the requirements aren’t met, the anticipated incentive payments may not be received, or may be recaptured into income after the fact. The program includes significant, and to some extent costly, administrative requirements that will affect project plans and execution strategies.

Project developers should focus now on making projects eligible for these cash incentives prior to the end of 2010. One of the most significant requirements is the necessity of beginning real construction activities by the end of that year.

NOTES

 

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i For example, the Tax Relief Act of 2003, the Economic Stimulus Act of 2008 and the American Recovery and Reinvestment Act of 2009 all included 50 percent bonus tax depreciation provisions, i.e. the ability to elect to  deduct against income (for qualified property) half of the cost of property in the first year of service. Under the most recent Act the 50 percent bonus depreciation election is available for qualified property whose use starts during 2008 or 2009 (2010 for certain longer-lived property).

 

In 2004 Calvin H. Johnson in a University of Texas Austin School of Law paper argued that 50 percent bonus depreciation is bad public policy because “investments in equipment that returns only 70 percent of the prevailing fair market value interest rates can go forward.” See Johnson, Calvin H., Depreciation Policy During Carnival: The New 50 Percent Bonus Depreciation, Tax Notes, Forthcoming.

 

Available at SSRN: http://ssrn.com/abstract=432161

 

ii For an example of the “monetization” of Internal Revenue Code (Code) §29 tax credits to raise capital examine the history of the Williams Coal Seam Gas Royalty Trust (NWSE:WTU) that was formed to provide investors with quarterly cash distributions and tax credits under §29 of the Code. The concept of “monetization” involves an owner of a property who is not able to use a tax credit to be able to sell an economic interest in the property to a tax oriented investor who is able to use the credit. Further information on the process of monetization of coal seam gas tax credits is available in a September 30, 1998 white paper, “Update on Application of §29 Tax Credit to Coal Seam Gas,” by Greg A. Sanderson and Lesley W. Berggren of Gomel & Davis, LLP under Work Assignment No. 4-1 of U. S. Environmental Protection Agency Contract 68-W5-0017.

 

See http://www.epa.gov/cmop/docs/pol003.pdf.

 

ⁱⁱⁱ See Karlgaard, Rich, “Waxman-Markey Flunks Math,” Fortune Magazine, August 3, 2009, p. 23.

 

ivFor additional information on the requirements of this economic stimulus program see: http://www.treas.gov/recovery/docs/guidance.pdf

What is the Dispute About?

In recent weeks a new and important states rights vs. Federal control issue has surfaced in the natural gas patch. The reason this dispute is important is that the result could potentially restrict development of the newly discovered-to-be-economic large shale natural gas plays in the U.S. These fields are primarily in Texas, Louisiana, Arkansas and Pennsylvania. The producer community is very alarmed and distrustful of the proposed new Federal drilling fluid disclosure rules, while environmental forces are claiming a need for more information to ensure the purity of water supplies that arguably might become polluted by drilling chemicals.

Who Introduced the Legislation?

According to Energy In Depth, the legislation introduced in Congress on June 9, 2009 by “…U.S. Reps. Diana DeGette (D-Colo.), Maurice Hinchey (D-N.Y.), and Jared Polis (D-Colo.), along with Sen. Bob Casey (D-Pa.) in the Senate,seek[s] to impose new restrictions on a safe and commonly used energy technology known as hydraulic fracturing – an essential technique for extracting hard-to-reach domestic energy while limiting disturbance to land. The legislation… is based on the notion that hydraulic fracturing is unsafe, unregulated, and that it benefits from a special exemption to federal law.”

What is the Major Political Issue?

The fact is that hydraulic fracturing is a long-tested drilling technique that is regulated by that states. However, proponents of the legislation claim that the failure to federally regulate the drilling fluids is an unacceptable exemption in 2005 Energy Legislation meant to benefit companies like Halliburton. They argue that disclosure of the content of the fluids is essential to protect ground water. Producers point out that most of the fuids are composed of water, and only a small amount of chemicals similar to those used in households are in the fluids.

I will continue to monitor this important economic issue and would be interested in your comments.

For more information, see the following links:

http://tinyurl.com/lpxzhl
http://www.pogam.org/news/view.asp?pID=1176
http://tinyurl.com/lxxdqm
http://www.energyindepth.org/wp-content/uploads/2009/06/friday-fact-check.pdf
http://www.energyindepth.org/2009/06/hinchey-no-need-to-put-hf-sdwa/
http://tinyurl.com/okecg2
http://tinyurl.com/nzsvge
http://tinyurl.com/md72f6
http://tinyurl.com/lv7dl4
http://waterunderattack.com/action-partners.php

An article was published recently in the Pipeline & Gas Journal about carbon capture and sequestration pipelines with the following title:

Carbon Capture And Sequestration (CCS): A Pipedream Or A Real Business Opportunity For Gas Pipeline Developers?
By Bruce E. Warner and Mark S. Shaffer | May 2009 Vol. 236 No. 5

Mark Shaffer is an associate of mine at Brown, Williams, Moorhead & Quinn, Inc.

Enjoy!

Bruce Warner

Wind Energy Primer Links

Wind Energy Basics
http://windeis.anl.gov/guide/basics/index.cfm

Wind Energy Resource Map – U. S.
http://windeis.anl.gov/guide/maps/map2.html

Wind Energy Atlas of the United States
http://rredc.nrel.gov/wind/pubs/atlas/atlas_index.html

Wind to Hydrogen Research Project
http://www.nrel.gov/hydrogen/proj_wind_hydrogen.html

Wind Energy for Water Applications
http://www1.eere.energy.gov/windandhydro/water_applications.html

Wind Energy for Thermoelectric Generation Water Supply
http://www1.eere.energy.gov/windandhydro/thermoelectric_generation_water_supply.html

Small Wind Systems to Power Your Home
http://www1.eere.energy.gov/windandhydro/small_wind_system_faqs.html

Wind Energy Links
http://windeis.anl.gov/guide/links/index.cfm

Smart Grid Articles
http://www.matternetwork.com/2009/6/duke-energy-cisco-partner-smart.cfm
http://www.energy.gov/news2009/7408.htm

Major CCS Funding by DOE
http://www.energy.gov/news2009/7405.htm

CCS Texas-Louisiana Pipeline
http://www.theadvertiser.com/apps/pbcs.dll/article?AID=2009905290305

CCS Project in the UK
http://news.bbc.co.uk/2/hi/uk_news/scotland/edinburgh_and_east/8072583.stm

CCS Demonstration Plant Largest in World in Louisiana
http://blog.al.com/live/2009/05/barry_power_plant_to_pump_gree.html

The Software Business of Tracking Carbon
http://www.forbes.com/2009/05/31/tracking-carbon-emissions-technology-enterprise-cap-and-trade.html?feed=rss_business_energy

Mini Nuclear Reactors
http://www.salon.com/wires/ap/business/2009/06/10/D98O0SMO0_us_new_reactor/

Duke to Shift Away from Coal Plants to Nuclear Due to Cost of CCS Regulations
http://communitypress.cincinnati.com/article/AB/20090526/BIZ01/305260027/Duke+plans+nuclear+shift

Solar Power Developments
http://www.greentechmedia.com/articles/read/brightsource-pge-sign-1.31gw-deal-in-california/
http://seekingalpha.com/article/139369-lockheed-martin-starwood-to-build-290mw-solar-thermal-plant-in-arizona?source=feed
http://www.kvoa.com/global/story.asp?s=10410225

Financing Green Energy Projects
http://www.forbes.com/2009/06/08/solar-wind-green-business-energy-banks.html?feed=rss_business_energy

Web Sites/Video Presentations

Evnviro Know – The Politics of Sustainability
http://ow.ly/15FX0D

E&E TV – Numerous Videos and an Archive on Current Energy and Political Topics
http://www.eenews.net/tv/video_guide/

Obama Administration Proposes Changes to Energy Priorities and Taxes As Reflected in the Recent Budget Proposal and Economic Stimulus Package:

Summary of Proposed Tax Changes As Reflected in Obama Administration 2009 Budget Proposal

• 1. Proposals to eliminate “oil and gas company preferences” worth $31.48 billion over 10 years
  • a. Expensing of intangible drilling costs
  • b. Repeal of the manufacturers’ tax deduction for oil and gas companies ($13.29 billion over 10 years)
  • c. Repeal of the percentage depletion allowance, important to small independent producers ($8.25 billion over 10 years)
  • d. Repeal of the enhanced oil recovery credit
  • e. Repeal of the marginal well tax credit
  • f. Repeal of the deduction for tertiary injectants
  • g. Repeal of the passive loss exception for working interests in oil and gas properties
• 2. Proposals to increase taxes on oil and gas
  • a. Excise tax on Gulf of Mexico production ($5.28 billion over 10 years)
  • b. Reduction to Gulf of Mexico royalty relief beginning in 2011 (related to an apparent government error to not include a provision in leases that would raise royalty payments in times of high oil prices).
  • c. A new 13 percent tax on all oil and gas production in the Gulf would affect companies not currently paying any royalties due to a “loophole”.
  • d. Increase the geological and geophysical amortization period for independent producers from 5 to 7 years ($1.19 billion over 10 years), reversing a provision in the 2005 Energy Policy Act
  • e. Reinstate the “Superfund” tax on refiners and petrochemical manufacturers (projected taxes of $1.2 billion in 2011, phasing to $2.3 billion in 2019 and totaling $17.2 billion in 2011-190)
• 3. Proposals to increase fees on producers
  • a. Charges to producers for user fees for processing permits to drill on Federal lands
  • b. Increases to “reform royalties and adjust rates”
  • c. Imposing a new fee, $4 per acre, on nonproducing Gulf leases that would raise $1.2 billion over ten years

Summary of Proposed Changes in Energy Policy Priorities

• 1. $19 million in the EPA budget to be used to upgrade greenhouse gas reporting measures.
• 2. Elaborate carbon “cap and trade” program to put a price(tax) on emitting pollution
  • a. Starting in 2012 the government would sell pollution permits, generating a projected $646 billion of revenue through 2019, or $78.7 billion per year starting in 2012.
  • b. The number of available permits would gradually decline, forcing businesses to buy increasingly scarce and costly rights on an open equities-style market.
  • c. The Administration hopes this will encourage businesses to invest in clean technologies as a cheaper alternative.
  • d. The goal is to double renewable energy production in three years and to have 10 percent of electricity generated from clean energy by 2012. Along with this the goal is to cut greenhouse gas production 14% below 2005 levels by 2020 and 83 percent by 2050.
  • e. The initial estimated carbon credit price is about $20 per ton.
  • f. Of the $646 billion, $120 billion, or $15 billion per year, would be invested in low carbon technologies starting in 2012.
  • g. The remainder of the $646 billion would be directed to disadvantaged communities and businesses to “help the transition to a clean energy economy.” The plan aims to help finance Obama’s tax credit for workers and to help with clean-up costs for small businesses.
  • h. The CBO estimates the revenue generated from a cap and trade system could ultimately range from $50 billion to $300 billion per year.
• 3. The Administration rejected permitting nuclear waste to be stored at Yucca Mountain in Nevada, after 20 years of plans and a cost of $9 billion.
• 4. The budget would end federal funding for ultra-deepwater oil and gas research and development.

Fifty Percent Business Bonus Depreciation Extended Through 2009
The 50 percent bonus tax depreciation provision included in the 2008 economic stimulus legislation was extended in the most recent economic stimulus package for expenditures made during 2009. The estimated cost of the extension was $5.07 billion over 10 years.

DOE Announces Changes to Expedite Funding Under the Economic Recovery Act

FAQS About ARRA 2009

Natural gas pipeline developers should be encouraged to facilitate the development of an interstate CCS pipeline transportation market. The pipelines have the skills and resources needed to provide this infrastructure within our economy. Within the United States somewhere between 3,000 to 4,000 miles of CCS pipelines have been developed over the past 30 years to transport CO2 for enhanced oil recovery. Given the emerging energy policies of the Obama Administration, a much expanded role for CCS pipelines lies in our future.

Pipelines can be built in three basic configurations to deliver CO2 to a “sink” area for injection into a salt cavern, depleted oil/gas field or non-mineable coal seam formation. The associated electric or natural gas power plant(s) that are the carbon source can be built directly over the “sink,” a single line can be built from the electric plant to the “sink” formation, or a network of CO2 pipelines can be built to transport the gas to the underground formations. Since some electric plants, such as peaking plants, do not run continuously, a network configuration may be favored to improve the load factor, and thereby the economics of the pipelines. Obviously, if the electric plant is located directly over the “sink” formation, the pipeline would be very short in length and would not be a major economic consideration. If the carbon capture site configuration and an available “sink” formation were relatively close to each other, single lines will likely evolve whose depreciable life would be tied to the physical and economic life of the power plant. A less extensive CO2 transportation network may evolve regionally in circumstances where power plant “farms” might be constructed due to favorable access to the electric grid, adequate water, and economic coal (including rail transport) or other fuel sources at a particular location. The evolution of a more extensive CO2 interstate transportation network might be more remote in its potential to evolve, and probably would be the last considered option if economics are permitted to prevail, even though improving the scale and volume of CO2 transportation would improve pipeline economics. Another factor that would play into economic evaluations will be the cost of and timing considerations associated with transporting energy by wire.

Before the market-place recognizes an extensive need for CO2 transportation facilities, a number of developments will need to occur. A carbon cap-and-trade law would improve the economics of carbon capture and sequestration facilities, such as those associated with coal power plants. CCS facilities increase the cost of delivered power substantially. Today, renewable electric generation options, such as wind or solar panels, appear be the preferred energy source alternatives by state regulators and national political leaders. Natural gas power plants also seem to be preferred over coal plants, even with potential CCS facilities, due to their relatively low capital cost requirements, shorter construction windows, and with more clarity today that significant additional gas supplies are available from non-conventional gas fields, such as the Barnett Shale fields of North Texas.

CO2 pipeline development requires an environment where CO2 is viewed by policy makers and the public as a commodity (rather than hazardous material) that can and should be safely transported and stored without significant leakage. This will require the evolution of several technologies and safety legislation, eminent domain transportation rights and clarity of CO2 environmental policies. Clarification of CO2 as a commodity, rather than a hazardous material, would facilitate transportation to remote storage sites and sequestration in applications where some economic benefit besides disposal can be realized, such as is currently the case with enhanced oil recovery. Thus, a number of important policy and legal matters need to be resolved before power plant developers and pipeline proponents will get a clear economic signal that an extensive CO2 transportation grid should be constructed.

Development of a pipeline network depends on the ability of electric distribution companies to pay for the facilities. Current state regulatory procurement processes that evaluate the best power source options will remain in place, and a power plant with CCS must be a best, or at least an acceptable, alternative to others in that planning process. The economics in part will depend on the cost of purchasing emissions credits as an alternative to CCS-related facilities once the cap-and-trade market fully evolves. Whether the CO2 transportation facilities are price-regulated or not is important, but not really the central question because the costs of transportation can be recovered by the pipeline developer if a contract with a credit-worthy electric LDC is in place. However, if CO2 transportation facilities were price-regulated, such as is the case today with interstate natural gas transportation facilities, this may help smooth approvals in the state-regulated energy procurement approval processes. Therefore, a jurisdictional transportation scheme would be likely more successful in its evolution. However, in the alternative policy makers could permit market-based or negotiated price options to evolve assuming a demonstrably competitive market for energy supply options.

CO2 pipelines are physically very similar to natural gas pipelines in almost all important respects. The pipeline and compression (or pumping) facilities can be built using transferrable, well-developed technology for similar costs per mile, though CO2 pipelines would likely more often be high pressure lines that is the case today for natural gas pipelines. CO2 pipelines would have electric compression or pumping facilities, rather than gas-fired compression which is more typical in the current interstate gas pipeline transportation network. CO2 pipelines do not corrode faster than natural gas pipelines as long as contaminants are controlled; thus, they do not inherently depreciate faster or slower than natural gas transportation facilities. Due to these factors, improving the cost of CO2 transportation would depend most importantly on government economic policies, such as the tax depreciable life, whether investment tax credits would be available and regulatory depreciation policies, such as the possible ability to defer depreciation until the full transportation demands evolve. Given favorable regulatory and tax policies, the facility costs could be recovered with a favorable depreciation scheme, such as levelized depreciation, and with the economics of tax incentives being transferred from the government to consumers. If the CO2 pipelines are non-price regulated facilities, the recovery of costs is simply a matter of negotiation between the electric LDC and the pipeline developer, a matter which is already well evolved for similar natural gas pipelines.

The circumstances that will drive the evolution of an extensive CO2 network are tied to technological developments and to large scale policy initiatives to sort out national energy source priorities.

I believe those interested in promoting CCS pipeline development should promote the following policies:

· CCS transportation as transportation of a commodity rather than as a hazardous material

· Eminent domain rights and certification of CCS transportation facilities

· Jurisdictional status and price regulation of interstate CCS transportation facilities with market-based pricing exceptions permitted for demonstrably competitive markets

· Economic incentives, such as favorable income tax treatment and innovative rate strategies, including negotiated rates and capacity release trading on CCS pipelines

Bruce E. Warner, CPA, CDP, CSS

March 2009

Author’s note: For more information on this topic, see the excellent article: “Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy Issues” by Paul W. Parfomak and Peter Folger”