Federal Oil And Gas Management: Opportunities Exist to Improve Oversight
Released: 2009-09-16T00:00:00

Letter

Interior’s Policies for Offshore and Onshore Oil and Gas Leases Differ in Key Ways

In October 2008, we reported that Interior’s policies for identifying and evaluating lease parcels and bids differ in key ways depending on whether the lease is located offshore—and therefore overseen by OEMM—or onshore—and therefore overseen by BLM. These differences follow.

Identifying lease parcels. OEMM’s and BLM’s methods for identifying areas to lease vary significantly. Specifically: For offshore leases, OEMM—as prescribed by the Outer Continental Lands Act—lays out 5-year strategic plans for the areas it plans to lease and establishes a schedule for offering leases. OEMM offers leases for competitive bidding, and all eligible companies may submit written sealed bids, referred to as bonus bids, for the rights to explore, develop, and produce oil and gas resources on these leases, including drilling test wells.

For onshore leases, BLM—which must follow the Federal Onshore Oil and Gas Leasing Reform Act of 1987—is not required to develop a long-term leasing plan and instead relies on the industry and the public to nominate areas for leasing. BLM selects lands to lease from these nominations, as well as some parcels it has identified on its own. In some cases, BLM, like MMS, offers leases through a competitive bidding process, but with bonus bids received in an oral auction rather than in a sealed written form.

Evaluating bids. OEMM and BLM differ in their regulations and policies for evaluating whether the bids received for areas offered for lease are sufficient. Specifically: For offshore leases, OEMM compares sealed bids with its own independent assessment of the value of the potential oil and gas in each lease. After the bids are received, OEMM—using a team of geologists, geophysicists, and petroleum engineers assisted by a software program— conducts a technical assessment of the potential oil and gas resources associated with the lease and other factors to develop an estimate of their fair market value. This estimate becomes the minimally acceptable bid and is used to evaluate the bids received. The bidder that submits the highest bonus bid that meets or exceeds MMS’s estimate of the fair market value of a lease is awarded the lease. These rights last for a set period of time, referred to as the primary term of the lease, which may be 5, 8, or 10 years, depending on the water depth. If no bids equal or exceed the minimally acceptable bid, the lease is not awarded but is offered at a subsequent sale. According to OEMM, since 1995, the practice of rejecting bids that fall below the minimally acceptable bid and re-offering these leases at a later sale has resulted in an overall increase in bonus receipts of $373 million between 1997 and 2006.

For onshore leases, BLM relies exclusively on competitors, participating in an oral auction, to determine the lease’s market value. Furthermore, BLM, unlike OEMM, does not currently employ a multidisciplinary team with the appropriate range of skills or appropriate software to develop estimates of the oil and gas reserves for each lease parcel, and thus, establish a market and resource-based minimum acceptable bid. Instead, BLM has established a uniform national minimum acceptable bid of at least $2 per acre and has taken the position that as long as at least one bid meets this $2 per acre threshold, the lease will be awarded to the highest bidder. Importantly, onshore leases that do not receive any bids in the initial offer are available noncompetitively the day after the lease sale and remain available for leasing for a period of 2 years after the competitive lease sale. Any of these available leases may be acquired on a first-come, first-served basis subject to payment of an administrative fee. Prior to 1992, BLM offered primary terms of 5 years for competitively sold leases and 10 years for leases issued noncompetitively. Since 1992, BLM has been required by law to only offer leases with 10-year primary terms whether leases are sold competitively or issued noncompetitively.

Interior’s Oversight of Federal Oil and Gas Production Has Not Kept Pace with Increased Activity

Oil and gas activity has generally increased over the past 20 years, and our reviews have found that Interior has—at times—been unable to meet its oversight obligations for (1) completing environmental inspections, (2) verifying oil and gas production, (3) performing environmental monitoring in accordance with land use plans, and (4) using categorical exclusions to streamline environmental analyses required for certain oil and gas activities. Specifically: Completing environmental inspections. In June 2005, we reported that, with the increase in oil and gas activity, BLM had not consistently been able to complete its required environmental inspections—the primary mechanism to ensure that companies are complying with various environmental laws and lease stipulations. At the time of our review, BLM officials explained that because staff were spending increasing amounts of time processing drilling permits, they had less time to conduct environmental inspections.

Verifying oil and gas production. In September 2008, we reported that neither BLM nor OEMM was meeting its statutory obligations or agency targets for inspecting certain leases and metering equipment used to measure oil and gas production, raising uncertainty about the accuracy of oil and gas measurement. For onshore leases, BLM had completed only a portion of its production verification inspections—with some BLM offices completing all of their required inspections and others completing portions as small as one quarter of their required inspections––because its workload has substantially grown in response to increases in onshore drilling. For offshore leases, OEMM had completed about half of its required production inspections in 2007 because of ongoing cleanup work related to Hurricanes Katrina and Rita. Additionally, in our ongoing work, we have found that Interior has not consistently updated its oil and gas measurement regulations. Specifically, OEMM has routinely reviewed and updated its measurement regulations, whereas BLM has not. Accordingly, OEMM has updated its measurement regulations six times since 1998, whereas BLM has not updated its measurement regulations since 1989.

Performing environmental monitoring. In June 2005, we reported that four of the eight BLM field offices we visited had not developed any resource monitoring plans to help track management decisions and determine if desired outcomes had been achieved, including those related to mitigating the environmental impacts of oil and gas development. We concluded that without these plans, land managers may be unable to determine the effectiveness of various mitigation measures attached to drilling permits and decide whether these measures need to be modified, strengthened, or eliminated. Officials offered several reasons for not having these plans, including that staff that could have been used to develop such plans had been busy with processing an increased number of drilling permits, as well as budget constraints.

Using categorical exclusions. Our report issued today on BLM’s use of categorical exclusions—authorized under section 390 of the Energy Policy Act of 2005 to streamline the environmental analysis required under the National Environmental Policy Act (NEPA) when approving certain oil and gas activities—identifies some benefits but raises numerous questions about how and when BLM should use these categorical exclusions. First, our analysis found that BLM used section 390 categorical exclusions to approve over one-quarter of its applications for drilling permits from fiscal years 2006 to 2008. While these categorical exclusions generally increased the efficiency of operations, some BLM field offices, such as those with recent environmental analyses already completed, were able to benefit more than others. Second, we found that BLM’s use of section 390 categorical exclusions was frequently out of compliance with both the law and agency guidance and that a lack of clear guidance and oversight by BLM were contributing factors. We found several types of violations of the law, such as BLM offices approving more than one oil or gas well under a single decision document and drilling a new well after statutory time frames had lapsed. We also found examples, in 85 percent of field offices reviewed, where officials did not comply with agency guidance, most often by failing to adequately justify the use of a categorical exclusion. While many of these violations and noncompliance were technical in nature, others were more significant and may have thwarted NEPA’s twin aims of ensuring that BLM and the public are fully informed of environmental consequences of BLM’s actions. Third, we found that a lack of clarity in both section 390 of the act and BLM’s guidance has raised serious concerns. Specifically: (1) Fundamental questions about what section 390 categorical exclusions are and how they should be used have led to concerns that BLM may be using these categorical exclusions in too many—or too few—instances; for example, there is disagreement as to whether BLM must screen section 390 categorical exclusions for circumstances that would preclude their use or whether their use is mandatory; (2) Concerns about key concepts underlying the law’s description of these categorical exclusions have arisen—specifically, whether section 390 categorical exclusions allow BLM to exceed development levels, such as number of wells to be drilled, analyzed in supporting NEPA documents without conducting further analysis; and (3) Vague or nonexistent definitions of key criteria in the law and BLM guidance have led to varied interpretations among field offices and concerns about misuse and a lack of transparency.

In light of our findings from this report, we recommended that BLM take steps to improve the implementation of section 390 of the act by clarifying agency guidance, standardizing decision documentation, and ensuring compliance through more oversight. We also suggested that Congress may wish to consider amending the Energy Policy Act of 2005 to clarify and resolve some of the key issues identified in our report.

Interior May be Missing Opportunities to Fundamentally Shift the Terms of Federal Oil and Gas Leases to Increase Revenues

In our past work, we have identified several areas where Interior may be missing opportunities to increase revenue by fundamentally shifting the terms of federal oil and gas leases. As we reported in September 2008, (1) federal oil and gas leasing terms result in the U.S. government receiving one of the smallest shares of oil and gas revenue when compared to other countries and (2) Interior’s royalty rate, which does not change to reflect changing prices and market conditions, led to pressure on Interior and Congress to periodically change royalty rates. We also reported that Interior was doing far less than some states to encourage development of leases. Specifically: The U.S. government receives one of the lowest shares of revenue for oil and gas resources compared with other countries and resource owners. For example, we reported the results of a private study in 2007 showing that the revenue share the U.S. government collects on oil and gas produced in the Gulf of Mexico ranked 93rd lowest of the 104 revenue collection regimes around the world covered by the study. Further, the study showed that some countries had increased their shares of revenues as oil and gas prices rose and, as a result, could collect between an estimated $118 billion and $400 billion, depending on future oil and gas prices. However, despite significant changes in the oil and gas industry over the past several decades, we found that Interior had not systematically re-examined how the U.S. government is compensated for extraction of oil and gas for over 25 years.

Since 1980, in part due to Interior’s inflexible royalty rate structure, Congress and Interior have been pressured—with varying success—to periodically adjust royalty rates to respond to current market conditions. For example, in 1980, a time when oil prices were high compared to today’s prices, in inflation-adjusted terms, Congress passed a windfall profit tax, which it later repealed in 1988 after oil prices had fallen significantly from their 1980 level. Later, in November 1995—during a period with relatively low oil and gas prices—the federal government enacted the Outer Continental Shelf Deep Water Royalty Relief Act (DWRRA) which provided for “royalty relief,” the suspension of royalties on certain volumes of initial production, for certain leases in the Gulf of Mexico in depths greater than 200 meters during the 5 years after passage of the act—1996 through 2000. For leases issued during these 5 years, litigation established that MMS lacked the authority under the act to impose thresholds. As a result, companies are now receiving royalty relief even though prices are much higher than at the time the DWRRAwas enacted. In June 2008, we estimated that future foregone royalties from all the DWRRA leases issued from 1996 through 2000 could range widely—from a low of about $21 billion to a high of $53 billion. Finally, in 2007, the Secretary of the Interior twice increased the royalty rate for future Gulf of Mexico leases. In January, the rate for deep water leases was raised to 16.66 percent. Later, in October, the rate for all future lease in the Gulf, including those issued in 2008, was raised to 18.75 perce Interior estimated these actions would increase federal oil and gas revenues by $8.8 billion over the next 30 years. The January 2007 increase nt. applied only to deep water Gulf of Mexico leases; the October 2007 increase applied to all water depths in the Gulf of Mexico.

We concluded that these royalty rate increases appeared to be a response by Interior to the high prices of oil and gas that have led to record industry profits and raised questions about whether the existing federal oil and gas fiscal system gives the public an appropriate share of revenues from oil and gas produced on federal lands and waters. Further, the royalty rate increases did not address industry profits from existing leases. Existing leases, with lower royalty rates, would likely remain highly profitable as long as they produced oil and gas or until oil and gas prices fell significantly. In addition, in choosing to increase royalty rates, Interior did not evaluate the entire oil and gas fiscal system to determine whether or not these increases were sufficient to balance investment attractiveness and appropriate returns to the federal government for oil and gas resources. On the other hand, according to Interior, it did consider factors such as industry costs for outer continental shelf exploration and development, tax rates, rental rates, and expected bonus bids. Further, because the increased royalty rates are not flexible with respect to oil and gas prices, Interior and Congress could again be under pressure from industry or the public to further change the royalty rates if and when oil and gas prices either fall or rise. Finally, these past royalty changes only affected Gulf of Mexico leases and did not address onshore leases.

Interior’s OEMM and BLM varied in the extent to which they encouraged development of federal leases, and both agencies did less than some states and private landowners to encourage lease development. As a result, we concluded that Interior may be missing opportunities to increase domestic oil and gas production and revenues. Specifically, in the Gulf of Mexico, OEMM varied the lease length in accordance with the depth of water over which the lease is situated. For example, leases issued in shallow water depths typically have lease terms of 5 years, whereas leases in the deepest areas of the Gulf of Mexico have 10 year primary terms; shallower water tends to be nearer to shore and to be adjacent to already developed areas with pipeline infrastructure in place, while deeper water tends to be further out, have less available infrastructure to link up with, and generally present greater challenges associated with the depth of the wells themselves. In contrast, BLM issues leases with 10 year primary terms, regardless of whether the lease happens to lie adjacent to a fully developed field with the necessary pipeline infrastructure to carry the product to market, or whether it is in a remote location with no surrounding infrastructure. Furthermore, BLM also uses 10 year primary terms in the National Petroleum Reserve-Alaska, where it is significantly more difficult to develop oil fields because of factors including the harsh environment. We also examined selected states and private landowners that lease land for oil and gas development and found that some did more than Interior to encourage lease development. For example, to provide a greater financial incentive to develop leased land, the state of Texas allowed lessees to pay a 20 percent royalty rate for the life of the lease if production occurred in the first 2 years of the lease, as compared to 25 percent if production occurred after the fourth year. In addition, we found that some states and private landowners also did more to structure leases to reflect the likelihood of finding oil and gas. For example, New Mexico issued shorter leases and could require lessees to pay higher royalties for properties in or near known producing areas and allowed longer leases and lower royalty rates in areas believed to be more speculative. Officials from one private landowners’ association told us that they too were using shorter lease terms, ranging from as little as 6 months to 3 years, to ensure that lessees were diligent in developing any potential oil and gas resources on their land. Louisiana and Texas also issued 3-year onshore leases. While the existence of lease terms that appear to encourage faster development of some oil and gas leases suggest a potential for the federal government to also do more in this regard, it is important to note that it can take several years to complete the required environmental analyses needed for lessees to receive approval to begin drilling on federal lands.

To address what we believed were key weaknesses in this program, while acknowledging potential differences between federal, state, and private leases, we recommended that the Secretary of the Interior develop a strategy to evaluate options to encourage faster development of oil and gas leases on federal lands, including determining whether methods to differentiate between leases according to the likelihood of finding economic quantities of oil or gas and whether some of the other methods states use could effectively be employed, either across all federal leases or in a targeted fashion. In so doing, we recommended that Interior identify any statutory or other obstacles to using such methods and report the findings to Congress.

We also noted that Congress may wish to consider directing the Secretary of the Interior to: convene an independent panel to perform a comprehensive review of the federal oil and gas fiscal system, and direct MMS and other relevant agencies within Interior to establish procedures for periodically collecting data and information and conducting analyses to determine how the federal government take and the attractiveness for oil and gas investors in each federal oil and gas region compare to those of other resource owners and report this information to Congress.

Interior’s Oil and Gas IT Systems Lack Key Functionalities

Our past work and preliminary findings have identified shortcomings in Interior’s IT systems for managing oil and gas royalty and production information. In September 2008, we reported that Interior’s oil and gas IT systems did not include several key functionalities, including (1) limiting a company’s ability to make adjustments to self-reported data after an audit had occurred and (2) identifying missing royalty reports. Since September 2008, MMS has made improvements in identifying missing royalty reports, but it is too early to assess their effectiveness, and we remain concerned with the following issues: MMS’s ability to maintain the accuracy of production and royalty data has been hampered because companies can make adjustments to their previously entered data without prior MMS approval. Companies may legally make changes to both royalty and production data in MMS’s royalty IT system for up to 6 years after the initial reporting month, and these changes may necessitate changes in the royalty payment. However, MMS’s royalty IT system currently allows companies to make adjustments to their data beyond the allowed 6-year time frame. As a result of the companies’ ability to make these retroactive changes, within or outside of the 6-year time frame, the production data and required royalty payments can change over time—even after MMS completes an audit—complicating efforts by agency officials to reconcile production data and ensure that the proper royalties were paid.

MMS’s royalty IT system is also unable to automatically detect instances when a royalty payor fails to submit the required royalty report in a timely manner. As a result, cases in which a company stops filing royalty reports and stops paying royalties may not be detected until more than 2 years after the initial reporting date, when MMS’s royalty IT system completes a reconciliation of volumes reported on the production reports with the volumes on their associated royalty reports. Therefore, it remains possible under MMS’s current strategy that the royalty IT system may not identify instances in which a payor stops reporting until several years after the report is due. This creates an unnecessary risk that MMS may not be collecting accurate royalties in a timely manner.

Additionally, in July 2009, we reported that MMS’s IT system lacked sufficient controls to ensure that royalty payment data were accurate. While many of the royalty data we examined from fiscal years 2006 and 2007 were reasonable, we found significant instances where data were missing or appeared erroneous. For example, we examined gas leases in the Gulf of Mexico and found that, about 5.5 percent of the time, lease operators reported production, but royalty payors did not submit the corresponding royalty reports, potentially resulting in $117 million in uncollected royalties. We also found that a small percentage of royalty payors reported negative royalty values, which cannot happen, potentially costing $41 million in uncollected royalties. In addition, royalty payors claimed gas processing allowances 2.3 percent of the time for unprocessed gas, potentially resulting in $2 million in uncollected royalties. Furthermore, we found significant instances where royalty payor-provided data on royalties paid and the volume and or the value of the oil and gas produced appeared erroneous because they were outside the expected ranges.

Moreover, in preliminary findings on Interior’s procedures for ensuring oil and gas produced from federal leases is properly accounted, we found that: The IT systems employed by both BLM and MMS fail to communicate effectively with one another resulting in cumbersome data transfers and data errors. For example, in order to complete the weekly transfer of oil and gas production data between MMS and BLM, MMS staff must copy all production data onto a disk, which then must be sent to BLM’s building where it is subsequently uploaded into BLM’s IT system. Furthermore, according to BLM staff, the production uploads are currently not working as intended. Frequently, an operator may make adjustments to production records, which results in the creation of a new record. When these new records are uploaded into BLM’s IT system, they should replace—or overlay—the prior record. However, due to technical problems, new reports are not correctly overlaying the previously uploaded production reports; instead they are creating duplicate or triplicate production reports for the same operator and month. According to BLM’s IT system coordinator, this will likely complicate BLM’s production accountability work.

BLM’s efforts to use gas production data acquired remotely from gas wells through its Remote Data Acquisition for Well Production program to facilitate production inspections have shown few results after 5 years of funding and at least $1.5 million spent. Currently, BLM is only receiving production data from approximately 50 wells via this program, and it has yet to use the data to complete a production inspection, making it difficult to assess its utility.

To address weaknesses we identified in our September 2008 report, we recommended that the Secretary of the Interior, among other things: finalize the adjustment line monitoring specifications for modifying its royalty IT system and fully implement the IT system so that MMS can monitor adjustments made outside the 6-year time frame, and ensure that any adjustments made to production and royalty data after compliance work has been completed are reviewed by appropriate staff, and develop processes and procedures by which MMS can automatically identify when an expected royalty report has not been filed in a timely manner and contact the company to ensure it is complying with both applicable laws and agency policies.

In addition, to address weaknesses identified in our July 2009 report, we made a number of recommendations to MMS intended to improve the quality of royalty data by improving its IT systems’ edit checks, among other things.

Interior’s RIK Program Continues to Face Challenges

Interior’s management and oversight of its RIK program has raised concerns as to whether Interior is receiving the correct royalty volumes of oil and gas. Both we and Interior’s Inspector General have issued reports detailing deficiencies in both program management and management ethics, including (1) problems with reporting the benefits of the RIK program to Congress, (2) Interior’s failure to use available third-party data to confirm gas production volumes, (3) inappropriate relationships between RIK staff and industry representatives, and (4) insufficient controls for monitoring natural gas imbalances, among others. Specifically: In September, 2008, we reported that MMS’s annual reports to Congress did not fully describe the performance of the RIK program and, in some instances, may have overstated the benefits of the program. For example, MMS’s calculation that from fiscal years 2004 to 2006, MMS sold royalty oil and gas for $74 million more than it would have received in cash was based on assumptions, not actual sales data, about the prices at which royalty payors would have sold their oil or gas had they sold it on the open market. MMS did not report to Congress that even small changes in these assumptions could result in very different estimates. Also, MMS’s calculation that the RIK program cost about $8 million less to administer than the royalty-in-value program over the same period did not include certain costs, such as IT costs shared with the royalty-in-value program that would likely have changed the results of MMS’s administrative cost analysis. In addition, MMS’s annual reports to Congress lacked important information on the financial results of individual oil sales that Congress could use to more broadly assess the performance of the RIK program.

In 2008, we also reported that MMS’s oversight of its natural gas production volumes was less robust than its oversight of oil production volumes. As a result, MMS did not have the same level of assurance that it is collecting the gas royalties it is owed. For instance, for oil, MMS compared companies’ self-reported oil production data with third-party pipeline meter data from OEMM’s liquid verification system, which records oil volumes flowing through pipeline metering points. Using these third-party pipeline statements to verify production volumes reported by companies would have provided a check against companies’ self-reported statement of royalty payments owed to the federal government. While analogous data were available from OEMM’s gas verification system, MMS did not use these third-party data to verify the company-reported production numbers. As of February 2009, MMS had begun to use the gas verification system.

Interior’s Inspector General also issued a report in September 2008 which found that the program had suffered from ethical shortcomings. In particular, the Inspector General found that a program manager had been paid for consulting by an oil and gas company in violation of agency rules and that up to one-third of all RIK staff had inappropriately socialized and received gifts from oil and gas companies.

Most recently, in August 2009, we found that MMS risks losing millions of dollars in revenue from the RIK natural gas program due to inadequate oversight. Specifically: MMS lacks the necessary information to quantify revenues resulting from imbalances—instances when MMS receives a percentage of total production other than its entitled royalty percentage. MMS does not know the exact amount it is owed as a result of natural gas imbalances because it lacks at least three types of information. First, it does not verify all gas production data to ensure it receives its entitled percentage of RIK gas. Second, MMS lacks information on how to price gas imbalances and when interest will begin accruing on imbalances for leases that have terminated from the program or those leases where production has ceased. Finally, MMS could be forgoing revenue because it lacks information on daily gas imbalances.

MMS also may be forgoing revenue because it does not audit operator data to ensure it has received its entitled royalty percentage. Although MMS has procedures for reconciling imbalances and uses OEMM’s gas verification system data where available, we found that it has not assessed the risk of forgoing audits at those measurement points where it does not have complete data with which to verify that it has been allocated its entitled percentage of gas. Although the RIK guidance letter to operators states MMS’s right to audit operator information related to RIK gas produced and delivered, MMS has not done so because it has considered its verification of operator-generated data to be sufficient. MMS has also claimed that it has saved money as a result of not auditing and that this is a benefit of the RIK program. However, other royalty owners and members of the oil and gas industry regularly audit operator-reported data to ensure that they have received the gas they are entitled to.

To address weaknesses we identified in our September 2008 and August 2009 reports, we recommended that the Director of MMS, among other things: improve calculations of the benefits and costs of the RIK program and the information presented to Congress by (1) calculating and presenting a range of the possible performances of the RIK sales in accordance with Office of Management and Budget guidelines; (2) reevaluating the process by which it calculates the early payment savings; (3) disclosing the costs to acquire, develop, operate, and maintain RIK-specific IT systems; and (4) disaggregating the oil sales data to show the variation in the performances of individual sales. improve MMS’s oversight of the RIK gas program and help ensure that the nation receives its fair share of RIK gas by (1) establishing policies and procedures to ensure outstanding imbalances are valued appropriately and that the correct amount of interest is charged; (2) monitoring daily gas imbalances and determining whether legislative changes are needed to require operators to deliver the royalty percentage on a daily basis; (3) auditing the operators and imbalance data; (4) promulgating RIK program regulations; and (5) establishing procedures, with reasonable deadlines, for resolving and collecting all RIK gas imbalances in a timely manner.

In conclusion, over the past several years, we and others have examined oil and gas leasing at the Department of the Interior many times and determined such leasing to be in need of fundamental reform across a wide range of Interior’s functions. As Congress considers what fundamental changes are needed in how Interior structures its oversight of oil and gas leasing, we believe that our and others’ past work provides a road map for successful reform of the agency’s oversight functions. If steps are not taken to effectively manage these challenges, we remain concerned about the agency’s ability to manage the nation’s oil and gas and provide reasonable assurance that the U.S. government is collecting an appropriate amount of revenue for the extraction and use of these scarce resources.

Mr. Chairman, this completes my prepared statement. I would be happy to respond to any questions that you or other Members of the Committee may have at this time.

GAO Contact and Staff Acknowledgments

For further information on this statement, please contact Frank Rusco at (202) 512-3841 or ruscof@gao.gov. Contact points for our Congressional Relations and Public Affairs offices may be found on the last page of this statement. Other staff that made key contributions to this testimony include Ron Belak, Ben Bolitzer, Melinda Cordero, Nancy Crothers, Heather Dowey, Glenn C. Fischer, Cindy Gilbert, Richard Johnson, Mike Krafve, Jon Ludwigson, Jeff Malcolm, Alison O’Neill, Justin Reed, Holly Sasso, Dawn Shorey, Karla Springer, Barbara Timmerman, Maria Vargas, Tama Weinberg, and Mary Welch.

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