HOUSTON, Feb. 02, 2016 (GLOBE NEWSWIRE) -- Memorial Resource Development Corp. (Nasdaq:MRD) announced today an operational update, year-end 2015 reserves, 2016 financial and operational guidance, updated horizontal drilling locations and hedge restructure. Highlights include:
- Estimated fourth quarter 2015 average daily production of 426 MMcfe/d
- Increased estimated full year 2015 production 72% to 345 MMcfe/d compared to 201 MMcfe/d for full year 2014
- Preliminary estimate of drilling and completion (“D&C”) capital expenditures of $511 million for the full year 2015
- Completed 6 gross horizontal wells in the Terryville Field during the fourth quarter 2015
- Scheduled to complete 15 gross horizontal wells in the Terryville Field in the first quarter 2016
- Scheduled to complete 15 gross horizontal wells in the Terryville Field in the first quarter 2016
Year-End 2015 Reserves:
- Reported year-end 2015 proved reserves of 1.4 Tcfe compared to 1.4 Tcfe at year-end 2014
- Increased proved developed producing (“PDP”) reserves 36% to 594 Bcfe at year-end 2015 compared to 436 Bcfe at year-end 2014
- Increased proved, probable and possible (“3P”)(1) reserves 80% to 8.0 Tcfe at year-end 2015 compared to 4.5 Tcfe at year-end 2014
- Management's estimate of 3P resources totaled 20.4 Tcfe at year-end 2015(5)
2016 Financial and Operational Guidance:
- Project 2016 daily production to average between 390 to 420 MMcfe/d
- Represents an approximate 18% increase over 2015's average daily production (using the mid-point of MRD's guidance range)
- Expect to operate an average of approximately 4 drilling rigs in 2016
- Includes development of MRD’s recently acquired acreage position by year-end 2016
- Estimate fiscal year 2016 D&C capital budget to total approximately $350 million (using the mid-point of MRD’s guidance range)
- Approximately 50% is expected to be spent in the first quarter 2016
- Flexible capital budget enables MRD to adjust spending levels during the second half 2016 as commodity prices warrant
- Capital budget expected to be approximately cash flow neutral
- Restructured 2018 natural gas and oil hedges into new oil and natural gas liquids ("NGLs") swaps in 2016
- Supports 2016 capital program and delineation plans, further strengthening MRD’s strong balance sheet
- Approximately 100% of expected 2016 production hedged at a total weighted-average price of $4.85 MMBtue
"We expect that MRD will report outstanding results for the fourth quarter and for the full year 2015. In 2015, a total of 33 gross horizontal wells were brought online with an average 30-day gross initial production rate of over 21 MMcfe/d. In addition to exceptional results in Terryville Field, we now control over 200,000 net acres in the over-pressured region of North Louisiana and look forward to delineating this acreage and seeing results by year-end 2016,” said Jay C. Graham, Chief Executive Officer of MRD.
Graham continued, “Our top priority for 2016 will be maintaining MRD’s strong balance sheet and solid debt metrics. We believe that MRD’s top-tier assets and extensive hedge book support our 2016 development and delineation program which will not only provide investors with peer-leading production growth, but will also drive net asset value expansion from the delineation results in our newly acquired acreage, all while spending approximately within cash flow. Most importantly, the flexibility built into our 2016 capital budget gives us significant optionality to adjust the program as commodity prices warrant."
Fourth Quarter and Full Year 2015 Operational Update
MRD expects to report estimated fourth quarter 2015 average daily production of 426 MMcfe/d, which represents a 64% increase from the fourth quarter 2014. MRD’s estimated production mix during the fourth quarter 2015 consisted of approximately 78% natural gas, 16% NGLs and 6% oil. MRD increased estimated full year 2015 production 72% to 345 MMcfe/d compared to 201 MMcfe/d for full year 2014.
MRD turned 6 gross wells to sales during the fourth quarter 2015, with a majority of these wells being brought online in late December 2015. On November 13, 2015, MRD completed the two-well Temple pad targeting the Upper Red zone. The Temple pad is significant as it represents one of the southernmost wells drilled to date. This two-well pad had an average lateral length of 7,009 feet and delivered a combined 30-day IP rate of 50.6 MMcfe/d. MRD is in the process of finishing up the completion of 5 new pads. These pads included a total of 13 gross wells consisting of 9 Upper Red and 4 Lower Red wells. Initial flowback rates from the combined wells completed during the fourth quarter 2015 and year-to-date 2016 have been encouraging, and management anticipates providing collective full thirty-day IP rates upon their availability at a later date.
Preliminary estimate of D&C capital expenditures, including facilities and capital workovers, totaled $120 million in the fourth quarter 2015. For the full year 2015, MRD’s preliminary estimate of D&C capital expenditures, including facilities and capital workovers, were approximately $511 million. Land and leasehold acquisitions totaled $368 million in 2015.
Year-End 2015 Proved Reserves
MRD reported year-end 2015 proved reserves of 1.4 Tcfe compared to 1.4 Tcfe at year-end 2014. MRD achieved significant positive performance revisions of 238 Bcfe, which were primarily due to the continued success of MRD's drilling program in the Terryville Field and were largely offset by price revisions. MRD’s 2015 drilling program was primarily inside its 1P area which limited the number of new PUD locations to be booked; however, we increased our year-end 2015 total proved original gas in place assumption in NSAI’s audit by approximately 37% compared to year-end 2014. At year-end 2015, MRD's proved reserves consisted of 71% natural gas, 24% NGLs and 5% oil.
|Summary of Changes in Proved Reserves||(Bcfe)|
|Balance as of December 31, 2014||1,378|
|Extensions, discoveries and additions||70|
|Balance as of December 31, 2015||1,378|
Netherland Sewell & Associates, Inc. (“NSAI”), an independent reserve engineering firm, audited MRD’s year-end reserves estimates as of December 31, 2015. Reserves as of December 31, 2014 are pro forma for the asset swap with Memorial Production Partners LP (MEMP) completed in February 2015 and Rockies divestiture completed in April 2015. The table set forth below provides additional information relating to MRD's reserves for the periods indicated below:
|As of December 31,|
|Proved developed reserves:|
|Natural gas (MMcf)||347,141||443,983|
|Proved undeveloped reserves:|
|Natural gas (MMcf)||640,428||529,831|
|Total proved reserves:|
|Natural gas (MMcf)||987,570||973,814|
|SEC PV-10(2) ($M)||$||2,807,760||$||932,553|
|MTM Hedge Value ($M)||365,389|
Using SEC prices, the present value discounted at 10% ("PV-10")(2) of MRD’s proved reserves at December 31, 2015 was $933 million (excluding MRD's hedges). The SEC rules require that proved reserve calculations be based on the average of the closing prices for the first day of each month in 2015. For the year-end 2015 reserve evaluation, the benchmark prices were $2.59 per MMBtu for natural gas and $46.79 per barrel for crude oil and compares to $4.35 per MMBtu for natural gas and $91.48 per barrel for crude oil for the year-end 2014. This represents a 41% and 49% year-over-year decrease in benchmark natural gas and crude oil prices, respectively.
MRD replaced 245% of estimated production in 2015 including performance revisions and excluding price revisions and acquisitions. Finding and development (“F&D”)(3) costs for proved reserve additions from costs incurred for D&C capital expenditures, including facilities and capital workovers, averaged $1.66 per Mcfe, based on preliminary unaudited capital expenditure amounts for 2015. The reserve life of MRD’s proved reserves, based on estimated 2015 production, is approximately 11 years. Additional detail regarding MRD’s calculation of its F&D costs can be found in the "Appendix" section of this press release.
Year-End 2015 3P Reserves and Management 3P Resources
NSAI audited 3P reserves at year-end 2015 were 8.0 Tcfe, an 80% increase over year-end 2014 3P reserves of 4.5 Tcfe. The year-over-year increase in 3P reserves was primarily driven by acreage additions in North Louisiana during 2015 in addition to NSAI’s revised original gas in place estimate in the Terryville Field.
The table below summarizes NSAI audited 3P reserve volumes using SEC pricing:
|3P Reserves (MMcfe)(4)|
Utilizing SEC pricing, management’s estimate of year-end 2015 3P resources(5) was 20.4 Tcfe. NSAI’s reserves methodology utilizes volumetric analysis whereas management’s methodology in determining its 3P resources is based on well spacing, lateral lengths and offset well performance.
(1) See “Cautionary Statements and Additional Disclosures" in the Appendix section of this press release for more information regarding 3P reserves.
(2) PV-10 is a non-GAAP financial measure. See “Cautionary Statements and Additional Disclosures" in the Appendix section of this press release for more information.
(3) See “F&D Cost Calculation” in the Appendix section of this press release for more information regarding MRD’s calculation of its F&D costs.
(4) MRD's 3P reserves at December 31, 2015 were prepared by its internal reserve engineers and audited by NSAI.
(5) See “Cautionary Statements and Additional Disclosures" in the Appendix section of this press release for more information regarding management's estimate of 3P resources.
Updated Horizontal Drilling Locations
As of year-end 2015, management estimates MRD has 3,847 gross horizontal drilling locations in its four primary, over-pressured zones located within its acreage position, which represent a significant increase from 1,115 gross horizontal locations previously reported at year-end 2014. Specifically, these management locations are represented by 1,773 Upper Red, 1,140 Lower Red, 465 Lower Deep Pink and 469 Upper Deep Pink gross horizontal drilling locations.
Of MRD’s total 3,847 management locations, 2,836 locations, or 74%, are included within NSAI’s 3P geographic area. Based on year-end 2015 reserves, NSAI audited MRD’s identification of 1,300 gross horizontal locations represented by 525 Upper Red, 431 Lower Red, 214 Lower Deep Pink and 130 Upper Deep Pink gross horizontal drilling locations. NSAI’s gross horizontal location count represents a 128% increase in the four primary zones compared to 571 gross horizontal locations at the year-end 2014.
2016 Operational and Financial Guidance
During 2016, MRD expects to operate an average of approximately 4 drilling rigs in North Louisiana, which compares to 8 operated rigs currently. MRD estimates its fiscal year 2016 D&C capital budget to total approximately $350 million, of which approximately 50% is expected to be spent in the first quarter 2016 to bring online 15 wells. MRD anticipates that 2016 average daily production will be between 390 MMcfe/d and 420 MMcfe/d, consisting of approximately 75% natural gas, 20% NGLs and 5% oil (using the mid-point of MRD’s guidance range). MRD expects this capital budget to be approximately cash flow neutral while providing approximately 18% annual production growth in 2016.
MRD plans to have approximately 30 drilled but uncompleted wells (“DUCs”) at the end of the second quarter 2016 by deferring completions on certain pads currently being drilled. MRD believes it has flexibility in its 2016 development plan not only in the timing of completions but also in its operated rig count as only one of its 8 currently operated rigs is contracted into 2017. The DUCs provide MRD the option to increase or decrease its activity as commodity prices warrant and allow MRD to preserve liquidity while maintaining flexibility in its completions schedule.
MRD expects to spud 15 to 20 gross wells in 2016. In addition, MRD expects to complete 30 to 35 gross wells during the year, including delineation of MRD's recently acquired acreage position. This compares to 33 gross wells completed in 2015. MRD expects total completions to consist of approximately 75% Upper Red wells, 20% Lower Red wells and 5% Upper and Lower Deep Pink wells. MRD estimates wells anticipated to be brought online in 2016 to have an average working interest of approximately 95%.
For the full year 2016, a summary of the guidance is presented below:
|2016 FY Guidance|
|Net Average Daily Production (MMcfe/d)||390||-||420|
|Natural Gas (% of Production)||74||%||-||76||%|
|NGLs (% of Production)||18||%||-||22||%|
|Oil (% of Production)||4||%||-||6||%|
|Average Costs (per Mcfe)|
|Gathering, Processing and Transportation|
|and BTU Adjustment ($/Mcfe)||($||1.05||)||-||($||0.75||)|
|Production and Ad Valorem Taxes (1)||($||0.15||)||-||($||0.10||)|
|Cash General and Administrative||($||0.30||)||-||($||0.25||)|
|Commodity Price Realizations (Unhedged) (2)|
|Natural Gas Realized Price (% of NYMEX to Henry Hub) (3)||95||%||-||100||%|
|NGL Realized Price (% of WTI NYMEX)||30||%||-||40||%|
|Crude Oil Realized Price (% of WTI NYMEX)||95||%||-||100||%|
|Wells Spud (Gross)||15||-||20|
|Wells Completed (Gross)||30||-||35|
|D&C Capital Expenditure ($MM)||$||325||-||$||375|
Note: Guidance as of February 2, 2016
(1) Amount varies based on abatement credits from newer horizontal wells
(2) Based on strip pricing as of January 22, 2016
(3) Does not include gathering, processing and transportation costs
The operational and financial guidance provided in this press release is subject to the cautionary statements and limitations described under “Cautionary Statements and Additional Disclosures – Forward-Looking Statements” in the Appendix of this press release. MRD’s guidance is based on, among other things, its current expectations regarding capital expenditure levels and the assumption that market demand and prices for oil, natural gas and NGLs will continue at a level that allow for economic production of these products.
During the fourth quarter 2015, MRD restructured its existing 2018 natural gas and oil hedges into new oil and NGL swaps for the period 2016. Specifically, MRD exchanged existing 2018 oil and natural gas hedges with a total volume of 270,896 MMBtue/d for new oil swaps in 2016 relating to 1,776 Bbls/d at an average price of $95.93 and new NGL swaps in 2016 relating to 8,224 Bbls/d at an average price of $44.55. The restructuring was exercised on a costless basis with the existing MRD individual counterparties within its lender group. Approximately $92 million of fair value associated with MRD’s 2018 contracts was exchanged in the fourth quarter 2015 and was used to acquire the new oil and NGL swaps that will settle during 2016. MRD plans to record any cash settlements received or paid associated with the new oil and NGL swaps within Adjusted EBITDA during the period in which the positions expire in 2016. The restructuring is not expected to have a material impact on the overall cash tax position of MRD.
As a result of the hedge restructure, MRD has hedged approximately 100% of its expected 2016 production on an equivalent basis at a total weighted-average price of $4.85 MMBtue. MRD's weighted average hedge price in 2016 is $3.76 per MMBtu of natural gas, $93.04 per Bbl of oil and $40.09 per Bbl of NGLs. Approximately 64% of MRD’s total natural gas hedge volumes in 2016 and 2017 are in the form of puts, which limit downside risk while providing upside potential. The net effect of the restructuring supports MRD’s 2016 capital program and delineation plans, further strengthens its peer-leading balance sheet and generates additional free cash flow. MRD expects to opportunistically re-hedge its expected 2018 production volumes. As of December 31, 2015, the mark-to-market value of MRD's hedge book was approximately $365 million.
The following table reflects MRD’s hedged volumes and corresponding weighted-average price, as of February 2, 2016.
|Natural Gas Derivative Contracts:|
|Total natural gas volumes hedged (MMBtu)||22,890,000||116,040,000||98,040,000|
|Total weighted-average price(1)||$||3.94||$||3.76||$||3.78|
|Crude Oil Derivative Contracts:|
|Total crude oil volumes hedged (Bbl)||249,000||1,075,960||336,000|
|Total weighted-average price(1)||$||88.57||$||93.04||$||84.70|
|Natural Gas Liquids Derivative Contracts:|
|Total natural gas liquids volumes hedged (Bbl)||489,000||5,238,004||–|
|Total weighted-average price(1)||$||41.52||$||40.09||–|
|Total Derivative Contracts:|
|Total hedged production (MMBtue)||27,318,000||153,923,781||100,056,000|
|Total weighted-average price(1)||$||4.85||$||4.85||$||3.99|
|Percent of expected production hedged(2)||70||%||100||%|
Note: 4Q 2015 hedge volumes represent the period October – December 2015
(1) Utilizing the mid-point for collars
(2) Using MRD’s 2015 and 2016 guidance ranges
Total debt outstanding as of December 31, 2015 was $1,023.0 million, including $423.0 million of debt outstanding under MRD’s revolving credit facility and $600.0 million of senior notes due 2022. As of December 31, 2015, MRD’s liquidity of $578.6 million consisted of $1.6 million of cash and cash equivalents and $577.0 million of availability under its revolving credit facility.
MRD is projected to exit 2016 with a net debt to annualized Adjusted EBITDA ratio of less than 2.5 times and total liquidity of over $500 million, based upon its current $1.0 billion borrowing base and its full year 2016 guidance which utilizes strip pricing as of January 22, 2016. MRD's liquidity position is expected to be sufficient to finance anticipated working capital and capital expenditures.
Fourth Quarter and Full Year 2015 Earnings Conference Call
MRD will report its fourth quarter and full year 2015 financial and operating results before the market opens for trading on February 24, 2016. Following the announcement, management will host a fourth quarter and full year 2015 earnings conference call at 2 p.m. Central (3 p.m. Eastern). Interested parties are invited to participate on the call by dialing (844) 735-9435, or (804) 681-3660 for international calls, (Conference ID: 36269632) at least 15 minutes prior to the start of the call or via the internet at www.memorialrd.com. A replay of the call will be available on MRD’s website or by phone at (855) 859-2056 (Conference ID: 36269632) for a seven-day period following the call.
About Memorial Resource Development Corp.
Memorial Resource Development Corp. is an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in North Louisiana. For more information, please visit our website at www.memorialrd.com.
The tables set forth below provide additional information relating to MRD's reserves. See “Cautionary Statements and Additional Disclosures" for more information regarding 3P reserves.
3P Reserve Detail (as of December 31, 2015):
F&D Cost Calculation:
F&D costs are calculated as D&C capital expenditures, including facilities and capital workovers, divided by reserve additions from extensions, discoveries, additions and performance revisions.
|Costs incurred ($’s in millions):|
|D&C and other expenditures||$||511|
|Reserve additions (Bcfe):|
|Extensions, discoveries and additions||70|
|Total F&D costs ($ / Mcfe)||$||1.66|
Cautionary Statements and Additional Disclosures
Except as otherwise indicated, the description of MRD’s business, properties, strategies and other information in this press release relates solely to the MRD Segment, which excludes the business, properties, strategies and other information regarding Memorial Production Partners LP.
Cautionary Statement Concerning Forward-Looking Statements
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as “anticipates,” “intends,” “will,” “plans,” “seeks,” “believes,” “estimates,” “could,” “expects” and similar references to future periods. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond MRD’s control. All statements, other than historical facts included in this press release, that address activities, events or developments that MRD expects or anticipates will or may occur in the future, including such things as MRD’s future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, future drilling locations and inventory, competitive strengths, goals, expansion and growth of MRD’s business and operations, plans, successful consummation and integration of acquisitions and other transactions, market conditions, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. All forward-looking statements speak only as of the date of this press release. Although MRD believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
MRD cautions you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond MRD’s control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to: commodity price volatility; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital; and the timing of development expenditures. Information concerning these and other factors can be found in MRD’s filings with the SEC, including its Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this press release are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by MRD will be realized, or even if realized, that they will have the expected consequences to or effects on MRD, its business or operations. MRD has no intention, and disclaims any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.
Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.
The preliminary results above are based on the most current information available to management. As a result, our final results may vary from these preliminary estimates. Such variances may be material; accordingly, you should not place undue reliance on these preliminary estimates.
PV-10, 3P Reserves and Management 3P Resources
PV-10 is a non-GAAP financial measure and represents the period-end present value of estimated future cash inflows from MRD’s natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. SEC pricing for natural gas and oil of $2.59 per MMBtu and $46.79 per Bbl and $4.35 per MMBtu and $91.48 per Bbl was based on the unweighted average of the first-day-of-the-month prices for each of the twelve months preceding December 2015 and December 2014, respectively. PV-10 differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes. Moreover, GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves. Because PV-10 estimates of probable and possible reserves are more uncertain than PV-10 and standardized estimates of proved reserves, but have not been adjusted for risk due to that uncertainty, they may not be comparable with each other. Nonetheless, MRD believes that PV-10 estimates for reserve categories other than proved present useful information for investors about the future net cash flows of its reserves in the absence of a comparable GAAP measure such as standardized measure. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from reserves on a more comparable basis. MRD expects to include a full reconciliation of PV-10 as of December 31, 2015 to standardized measure in its Form 10-K for the year ended December 31, 2015. Neither PV-10 nor standardized measure represents an estimate of fair market value of MRD’s natural gas and oil properties. MRD and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.
MRD has provided summations of its proved, probable and possible reserves and summations of its PV-10 for its proved, probable and possible reserves in this press release. The SEC strictly prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Investors should be cautioned that estimates of PV-10 of probable reserves, as well as the underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. Further, because estimates of probable and possible reserve volumes have not been adjusted for risk due to this uncertainty of recovery, their summation may be of limited use.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms. “3P resources” is not a term defined by the SEC or by the Society of Petroleum Engineers; instead, MRD management believes that it is a reasonable estimate of the potential hydrocarbons recoverable from the relevant properties using assumptions regarding well spacing, lateral lengths and offset well performance that are different than those used in determining proved, probable or possible reserves. Management’s estimate of 3P resources is based on analogy to MRD’s existing models applied to additional acres and differs from NSAI’s reserve estimation methodology in certain respects, including spacing assumptions and recognizing hydrocarbons at identified drilling locations that would not constitute proved undeveloped locations. MRD’s estimate of 3P resources includes hydrocarbons that may potentially be discoverable through exploratory drilling or recovered with additional drilling or recovery techniques. These hydrocarbons may not constitute “reserves” within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules. Other companies may use a different term or may define that term differently. While MRD believes its calculation of 3P resources is reasonable, such estimate has not been reviewed by third party engineers or appraisers. Investors are cautioned to review 3P resources together with the breakdown of MRD’s reserves by category as set forth in this press release. You should not assume that management’s estimate of 3P resources is comparable to proved, probable or possible reserves or represents an estimate of future production from properties. Management’s estimate of 3P resources and drilling locations have not been fully risked by MRD management and are inherently more speculative than proved, probable or possible reserves estimates. Actual locations drilled and quantities that may be ultimately recovered from MRD’s interests could differ substantially. There is no commitment by MRD to drill all of the drilling locations which have been attributed to these quantities.
Adjusted EBITDA is defined as net income (loss), plus interest expense; debt extinguishment costs; income tax expense; depreciation, depletion and amortization; impairment of goodwill and long-lived properties; accretion of asset retirement obligations; losses on commodity derivative contracts and cash settlements received; losses on sale of properties; stock-based compensation; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP; cash distributions from MEMP; transaction related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; equity income from MEMP; gains on sale of assets and other non-routine items.
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