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December 31, 2012 • Volume 05, No. 21
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ECTOR CO., TX NONOP SALE 21-Active Wells. 8-Drilling. 6-Completions.SPRABERRY TREND AREAWOLFBERRY PRODUCING ZONE PPUpside Potential: 31 Permits3-AFEsInterest Under 5 Contiguous SectionsWells Being Drilled On 20 Acre Spacing~1.5% NonOperated WI; ~1.125% NRIGross Prod: 1.3 MBO & 2.1 MMCFD SPRA-Net Production: ~17 BOED BERRYNet Cash Flow: ~$44,000/MonthEUR/Well ~145-190 MBOECALL PLS AGENT FOR INFOPP 2124DV
PERMIAN SALE PACKAGE 27-PDP Wells. ~1,930 Net Acres.MIDLAND, ECTOR & ANDREWS CO.SPRABERRY (TREND AREA) PPMultipay: Wolfberry; Strawn, Wolfcamp---Dean, Spraberry & Clearfork50-100% OPERATED WI; 75% NRIGross Prod: 573 BOPD & 1,284 MCFD 445Net Prod: 320 BOPD & 741 MCFD BOEDNet Cash Flow: >$1,000,000/MnSubstantial Drilling UpsideMost Acreage is HBP. 2 Wells HBP 100%CALL PLS FOR MORE INFOPP 1695DV
FEATURED DEALS
Oil forecasts vary on supply growth & shaky demand
Crude price projections are all over the map for next year. RBC anticipates WTI ranging $70-$90/bbl in 2013 with major drivers being a continued Cushing bottleneck and a weaker dollar on the back of US quantitative easing. Raymond James predicts WTI could hit the mid-$60s partly on the failure of storage infrastructure to keep pace with surging production. Standard & Poor’s is
more optimistic but still believes WTI will remain below $90 on increased drilling. Goldman Sachs and BofA Merrill Lynch think Brent will average $110/bbl and Goldman sees an exit rate near $105/bbl as more capacity comes online and supply loosens.
Will average natural gas prices top $4.00 in 2013? Despite ending 2012 with roughly half as many gas-directed rigs as it had at the
beginning of the year, the US is projected to maintain production levels next year (up 0.6% to 69.6 Bcfd according to the EIA) with prices consequently remaining below $4.00/MMbtu. Standard & Poor’s sees abundant supply and leveling demand—including an end to the coal-to-gas switching trend in the
power sector—keeping prices below the $4.00 threshold. S&P says recent price recovery won’t be sufficient to lure operators back to dry gas, where profitability requires at least $4.00-
$4.50. As a result, production declines are expected after next year. Barclays roughly agrees, calling for $3.70 gas next year (revised upward from an earlier $3.25 forecast) and a drop of up to 50% in coal-to-gas switching vs. 2012 rates.
On the other hand, Chesapeake sees a multi-year price rebound that could start as early as 2013—driven by big producers’ switch to oil drilling plus growing demand “across all sectors of consumption.” The company is putting its money where its mouth is, remaining essentially unhedged for 2013. In a Q3 earnings call, CEO Aubrey McClendon said the gas price strip for 2013 and years beyond “does not reflect a full appreciation of what happens when big producers like us reverse course and go into managed decline.” By its own numbers, Chesapeake accounts for 30% of US gas production growth over the past five years. The company expects its 2013 gas output to be down 7% YOY, and “when we roll over, we think we will pull the whole market with us,” according to McClendon. Chesapeake has cut gas drilling from 81 rigs total to five in the Marcellus and four in other shales, and does not plan to reverse course until prices hit $5/MMbtu.
All signs point to increased US gas demand next year—with disagreement limited to how much growth and how fast.
1. WTI ends 2012 at $92.27, down 8% YOY.
2. Gas loses 3.4% last trading day to end 2012 at $3.35—still up 75% from April bottom.
3. WTI-Brent spread seen at $9 through 2014, but down to $2 after 2020.
4. EIA expects flat gas production in 2013 at 69.6 Bcfd.
5. Oil & gas production hit recent record highs.
QuickLook OILGAS
RBC sees WTI in $70-$90 range next year, RJ in the $60s, S&P just below $90.
Barclays & S&P see Henry Hub below $4 in 2013, Chesapeake is more bullish.
Continues On Pg 5
Continues On Pg 2
Crude Oil & Natural Gas Closing PricesCurrent 12/31/12
6 Mths Ago 06/29/12
1 Yr Ago 12/30/11
2 Yrs Ago 12/31/10
Oil
WTI Front Month $91.82 $84.96 $98.83 $91.38
WTI 12-Mth Strip $93.00 $87.10 $98.85 $93.68
Brent Front Month $111.11 $97.80 $107.38 $94.75
Brent 12 Mth Strip $107.27 $97.96 $105.43 $93.95
Gas
Henry Hub Front Month $3.35 $2.82 $2.99 $4.41
Henry Hub 12 Mth Strip $3.60 $3.29 $3.30 $4.64
Financial
S&P 500 1,426.19 1,362.16 1,257.60 1,257.64
Source: CME Group & ICE
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QuickPrice 2 December 31, 2012
Chesapeake is predictably more bullish on coal-to-gas switching for power generation than S&P or Barclays, and when you add increased use as chemical feedstock for manufacturing and possible LNG exports, McClendon says we are heading for a YOY storage deficit just months after analysts were worrying about US gas storage reaching maximum capacity.
In manufacturing, Barclays sees industrial demand growing to 19 Bcfd next year while Morgan Stanley thinks new projects could grow US and Canadian gas
demand 3.3 Bcfd by 2020. Enough projects to grow demand 5.3 Bcfd are already on paper, but Morgan Stanley assumes that some of these will fall off due to capital or feedstock costs or permitting issues. Despite demand growth, Morgan Stanley sees North American gas staying below $6/MMbtu through 2021 on overwhelming supply.
On the power generation front, Bentek predicts gas will hit 32% of the total US power mix by 2017. Although it touched these levels multiple times last year, gas has averaged only 23% of the power mix over the past five years. Gas-fired generation grew 20% this year to 186 megawatt-hours per year, and Bentek sees future annual growth of 15% until
another 170 megawatt-hours per year have been added. Meanwhile, Bentek sees gas displacement of coal tripling from a
five-year average 2.6 Bcfd to 7.8 Bcfd in 2017. Gas burn for power should grow 16% to 29 Bcfd during the same period. Bentek said the paradigm shift will result in “increased price responsiveness by gas producers and the power industry, greater price volatility, infrastructure expansions and greater integration of the gas and electricity grids.”
As for LNG, the US Department of Energy recently came out in favor at least by proxy, releasing a report by NERA Economic Consulting that concluded the more LNG we export, the larger the net benefit to the economy. Higher export earnings are expected to offset modest price increases to homes and businesses. The study found prices would most likely rise less than $0.33/Mcf in 2010 dollars, with increases after five years likely in the $0.22-$1.11 range. Resource owner income is projected to rise, partially offset by total labor compensation and investment income declines. The legal standard controlling DOE decisions on these matters is to allow exports unless they “will not be consistent with the public interest.” Given the report’s findings, such a conclusion would be a tough sell. Conditional approval of export projects is most likely, with possible volume caps, periodic economic impact reviews and/or other limits. Should gas prices rise significantly, however, the political landscape could change quickly.
Henry Hub price firms up as natural gas glut ends
Fortunately, natural gas appears to have fought through its bottom this year with brighter days ahead. This time last year, front-month Henry Hub prices were in the lower $3s, just breaking through to $2.99/MMbtu on the last trading day of 2011. The bottom fell out a few weeks into 2012 as a perfect storm of overproduction concerns and freakishly warm weather pushed gas as low as $1.91 in April.
Shut-ins and power switching helped bring in the multi-year bottom with prices quickly bouncing into a $2.20-$2.75 range. Many analysts said the upper limit was the price at which power switching remained viable for utilities. Summer and into September brought a higher $2.70-$3.10 range as dramatic cuts to the gas rig count took effect and the storage overhang was hacked to manageable levels.
As storage confidence grew and prognosticators called for a colder winter than last year’s anomaly, autumn brought prices in the $3.30-$3.90 range. Much of the bullish outlook was supported by cheaper gas-associated NGL feedstocks, which combined with
cheap gas itself spawned significant buzz regarding reinvigoration of the US manufacturing base. With the storage glut all but gone, front-month gas closed the year up ~75% from the $1.91 bottom and up ~11% YOY despite a 3.4% December 31 drop to $3.35/MMbtu.
It is important to note that while we appear to be through the worst of things from a pricing perspective, one major 2012 impact that has only begun to be felt is impairments to PV-10 values for assets used to calculate proved reserves under SEC rules. Data recently calculated by Ryder Scott indicates 2012 average first-day-of-month Henry Hub cash prices of $2.76/MMbtu, down 33% vs. 2011’s average. Thus significant downward reserve revisions such as occurred in Q3 and Q4 will likely continue, with many likely to be revealed in operators’ year-end reports.
GASCHK thinks its production cuts will put
strong upward pressure on gas prices.
Bentek: Gas will generate 32% of power by 2017; others see less switching from coal.
Will average natural gas prices top $4.00? Continued From Pg 1
Gas ending 2012 up ~75% from April lows & up ~15% YOY.
Expect large downward reserve revisions in gas operators’ 2012 year-end reports.
LNG exports get boost from DOE report finding huge benefits & minor price hike.
Natural Gas (Near Mth Contract Last-2 Wks w/Volatility Index)
Source: NYMEX via www.cmegroup.com
Volume 05, No. 21 3 Marketalert
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Production renaissance characterizes 2012 in the US The oil and gas industry can take pride in the fact that recent production
data for both oil and gas is crashing through multi-year records and helping the US begin to see a way to its 40-year-old dream of energy independence. EIA data for September showed oil production of ~6.5 MMbopd in the US, the
highest monthly average since January 1998 and a ~16% YOY increase driven by Texas and North Dakota. Texas production
grew over 500,000 bopd YOY to more than 2.0 MMbopd largely on Eagle Ford and Permian activity, while the Bakken drove North Dakota production up by more than 250,000 bopd to nearly 750,000 bopd. Gains in Oklahoma, New Mexico, Wyoming, Colorado and Utah also contributed to the record.
Meanwhile despite conventional wisdom predicting otherwise, September gas production rose 9% sequentially to a new recent high of 69.4 Bcfd. Part of the increase was due to recovery from August’s Hurricane Isaac impacts, but the month also corrected other organic declines from earlier in the year. September’s
gas production surpassed that of any other month since February 1973. This is somewhat surprising given that gas
drilling has dropped significantly this year on a gas glut caused by overproduction and a freakishly warm winter. In April, storage eventually built to record levels roughly 55% above that of the year-ago prior and 60% above the five-year storage average. Many operators responded by curtailing drilling and shutting in production. But power generators rode to the rescue by increasing demand, and later in the year midstream buildout helped production get to market. The EIA has revised its full-year production forecast upward 0.4 Bcfd to 69.2 Bcfd in light of the September build.
This multi-year record gas production led to at least one all-time record, with natural gasoline exports to Canada hitting 160,000 bpd (the highest on record) in September. The NGL is largely serving as a diluent for oil sands transport, which becomes more important in the winter as the heavy crude’s viscosity increases. Natural gasoline exports have also been driven higher by cheaper ethane and propane supplanting the liquid from its former role as an ethylene and propylene feedstock.
September crude production highest in over 14 years at 6.5 MMbopd.
September gas production highest in nearly 40 years at 69.4 Bcfd.
Natural gasoline exports to Canada hit all-time high of 160,000 bpd.
U.S. Monthly Crude Oil Production Reaches Highest Level Since 1998
Source: EIA www.eia.gov
ARK-LA-TEXCLAIBORNE PH, LA PROPERTY5-Active Wells. 4-NonProducing.LISBON FIELD PP~32%-100% OPERATED WI FOR SALEAvg Production: 44 BOPD & 580 MCFD 580Avg Net Income: $82,028/Month MCFDCONTACT AGENT FOR UPDATEPP 1859
GULF COASTSOUTH TEXAS PROPERTIES7-Active Wells. 6-Shut In. 1-SWD.ATASCOSA & FRIO CO.EAST CROWN FIELD (3,522-Acres) PPOlmos Formation Production. 4,200 Ft.Depths Limited to Top of Austin Chalk.40% NonOperated WI; 30% NRI 45Gross Production: 50-60 BOPD BOPDNet Production: 15-18 BOPDNet Cash Flow: $15,000-$30,000/MonthCONTACT SELLER FOR MORE INFOPP 1872DV
MATAGORDA CO., TX PROSPECTPUD Oil Prospect. 10,500’ TD.TEXAS GULF COASTUpdip to 400,000 Barrels Oil DVAdditional Secondary Objectives.3D Seismic & Subsurface Geology Data.50% NonOperated WI; 75% NRI (Lease) GULFExpected IP: 150 BOPD COASTEstimated Reserves: 350 MBODHC: $850,000; Compl: $450,000CONTACT GENERATOR FOR INFODV 1866
SOUTHEAST TEXAS PROSPECTMultiple Drill Locations.PROLIFIC SALT DOMEMultipay Zones to >6,500 Ft. DVDevelopment 2-D & 3-D Seismic.SEEKING JOINT VENTURE PARTNER SALTInvestor Oriented Public Company. DOMECONTACT GENERATOR FOR INFODV 1837
PERMIAN BASINLEA CO., NM PROSPECT320-Net Acres.PERMIAN BASIN12,000’ Normal Pressure Devonian Test. DV3D Seismic & Subsurface Geology Data.100% OPERATED WI; 75% NRIExpected IP: >300 BOPDAnalog Fields Produced 59 MMBO PERMIANEstimated Reserves: 680 MBO BASINDHC: $1,500,000; Compl: $400,000CONTACT GENERATOR FOR INFODV 1849
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ROCKIESCAMPBELL CO., WY PROSPECT2-3 Potential Wells. ~200-Acres.POWDER RIVER BASINMINNELUSA FORMATION DVMinnelusa Lower B Section. 8,000 Ft.100% OPERATED WI; 79.5%-82.5% NRI-- Seller Carries 5.0% WI To Tanks.Offset Unit Cumm’d: 6.2 MMBO MINNELUSAEst Prospect Reserves: ~1.0 MMBOCompleted Well Cost: ~$1,000,000CONTACT SELLER FOR MORE INFODV 2885
ROCKIESLARAMIE CO., WY ROYALTY1-Well.SILO FIELDNiobrara to B2 Centerline. RRDepth: 8,195 Ft. to 13,093 Ft. (MD)Well Completed August 2012.1.83% Gross ORR For Sale ---- 0.45833% Net ORRI in Hawkeye WellGross: 477 BOPD; Net: 64 BOPD ORRIMonthly Cash Flow: $4,864/MonthOperator: Kaiser-Francis Oil CompanyCONTACT COLORADO COMPANYRR 1834PP
WEST COASTNYE CO., NV ACREAGE187,170-Net Acres. Mostly Contiguous.HOT CREEK VALLEYAdjacent to Productive Railroad Valley LMississippian Chainman Shale ---- & Devonian Pilot ShaleMultiple Paleozoic Conventional ReservoirsPOTENTIAL HORIZONTAL EXPLORATION CHAIN-100% OPERATED WI FOR SALE MANOffset to Major Oil - Eblana No. 1BLM Leases - 9.5 Year Term RemainingCONTACT SELLER FOR DETAILSL 1874DV
GULF OF MEXICOGULF OF MEXICO OVERRIDE6-Blocks.OFFSHORE LOUISIANAShip Shoal 182/183 RRSouth Timbalier 36/37Eugene Island 339 & 34280% ORRI SALE OF A 25% NPI OFF-Operators: Chevron & Apache Corp SHORECONTACT AGENT FOR UPDATERR 1863
EASTERN & APPALACHIA BASINPENNSYLVANIA ACREAGE~123,000-Total AcreagePOTTER, MCKEAN, MERCER, INDIANA,VENANGO, CRAWFORD, CAMBRIA -- L-- & CLARION COUNTIESUtica Shale Play Trend UTICA100% OPERATED WI FOR LEASENRI IS NEGOTIABLECONTACT LESSOR FOR DETAILSL 1841DV
WESTERN PA PIPELINE CORRIDOR~85 Miles Owned In Fee Simple.VENANGO, BUTLER, CLARION& JEFFERSON CO., PENNSYLVANIA GRight-Of-Way Allows for Multiple Pipes.Ready For New Pipe Construction.CONTIGUOUS OFFERING PIPE-Abandoned Railway, Cleared & Graded. LINETitle Verification Underway.Maps & Shapefiles Available By Request.CONTACT SELLER FOR DETAILSG 1838
ROCKIESBAKKEN NON-OPERATED PACKAGE54 Wells. 16-Counties.NORTH DAKOTA & MONTANABakken & Sanish Production PPSome Acreage HBP.Varying NonOperated WI; Avg NRI ~80%Net Production ~60 BOEDOperators Include: Continental, EOG------Hess, Newfield, Hunt & Others BAKKENInterest In 47 Active Drilling Units.Exposure To ~70 Additional Drilling Units.36 Wells Drilling, Permitted or Proposed.Permits By: Continental & Petro-HuntCALL PLS FOR MORE INFOPP 8174DV
ROCKIES SALE PACKAGE34-Active Wells. 2-SWD.NORTH DAKOTA & MONTANAWILLISTON BASIN PPProducing from Madison Formation.4 NonOperated Behind Pipe Opportunities.LOW RISK, LONG LIFE PRODUCTIONNonOperated & Operated WI Available13-81% WORKING INTEREST FOR SALE ~260Net Production: ~260 BOED (86% Liquids) BOEDSale Does Not Include Bakken/TF InterestCGA Reserve Report Available.CONTACT AGENT FOR UPDATEPP 1896DV
PERMIAN BASINCROCKETT CO., TX ACREAGE5,280-Gross/Net Acres.PERMIAN BASIN LEASEHOLDHorizontal Wolfcamp Potential DVBelow the San Andres Formation.Additional Possible Potential Zones:Vertical Wolffork & Wolfcamp D.100% OPERATED WI; 75% NRI17-Total Blocks; Will Sell Entire -- WOLF--- Package or As Individual Blocks CAMPHorizontal Wolfcamp EUR:450 MBOE/Well (Approach Resources)598 MBOE/Well (Apache Corp.)CONTACT AGENT FOR UPDATEDV 1892L
WEST TEXAS OVERRIDEMultiple Active Wells.PERMIAN BASIN - ANDREWS CO.SOUTH FUHRMAN MASCHO UNIT RR2.5% ORRI FOR SALEGross Prod: 646 BOPD & 672 MCFD 758Avg Net Cash Flow: $49,881/Month BOEDCONTACT AGENT FOR UPDATERR 1856PP
MIDCONTINENTJONES CO., TX PROSPECT7-Potential Wells.EASTERN SHELFExcellent Multi-Zone Prospect DVObj 1: Swastika. 3,060 Ft.Obj 2: Canyon Sands. 3,675 Ft.Obj 3: Strawn Sands. 4,800 Ft.Subsurface Geology Data Available EASTERN35% NonOperated WI; 80% NRI SHELFEst. Well Reserves: 100 MBO/WellEst. Project Reserves: >700 MBODHC: $230,000; Compl: $200,000CONTACT SELLER FOR MORE INFODV 1902
EASTERN & APPALACHIA BASINOHIO NON-PRODUCING ROYALTIES~12,000-Acres.STARK, MAHONING, JEFFERSON,--HARRISON, COLUMBIANA, CARROLL, RR-- & BELMONT COUNTIESUTICA SHALE PLAY5.0% ORRI FOR SALE ROYALTYException of 1.5% in 820 Acres.5-Year Term Plus 5-Year Option to RenewCALL LESSOR FOR MORE INFORR 1867
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Volume 05, No. 21 5 Marketalert
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BofA discussed a tight international market on North Sea declines, with Iranian production as a question mark. The Economist Intelligence Unit’s Peter Kiernan said overall prices should come down on weak demand, projecting even developing nations will see poor economics in 2013. Kiernan tempers this point by noting that the trend of more expensive finds as well as the Middle East risk premium could support a price floor.
The substantial (currently ~$20) WTI-Brent spread is largely expected
to endure next year, maintaining rough parity with increasing US production and slowing Chinese demand. However,
the EIA anticipates a $9 spread next year and in 2014, shrinking to ~$2 after 2020. Many expect the spread to be winnowed down with the eventual completion of TransCanada’s Keystone XL pipeline. But EIA considers WTI supply distortions a serious enough phenomenon that it recently announced it would begin using Brent as the reference oil price in its annual energy outlook. The agency explained the move by noting that gasoline and diesel prices now track Brent more closely than WTI, and said it wants to more accurately reflect the price refiners are paying for light, sweet crude.
Beyond next year, BofA Merrill Lynch sees surging production pushing prices downward with the possibility of touching a $50 WTI handle before the end of 2015, which could in turn slow output. Further down the line, the EIA sees shale and tight oil feeding US crude production growth of 234,000 bopd per year to a 2019 peak of 7.5 MMbopd. The National Intelligence Council (which advises the US director of national intelligence) is much more bullish, projecting shale oil could grow US production as high as 15 MMbopd by 2020, with breakevens running anywhere from $44-$68/bbl and the US potentially becoming a “major” energy exporter. The NIC forecast takes into account continued technological advances in E&P that the council says may not have been factored into other analyses. The NIC called the shift “tectonic,” predicting that US energy independence could come as soon as 10-20 years with the added side benefit of mitigating OPEC pricing power. However, such a scenario could also lead to a global pricing collapse on oversupply. Brent, according to the EIA, should bottom in 2015 at $96/bbl and then begin slowly rising on growing demand supporting costlier resource development.
US supply, Europe & Middle East drove crude in 2012
Oil prices were driven by a mix of supply, macroeconomic and international security concerns in 2012 and closed the year down ~8% YOY. WTI traded in the $100-$110/bbl range through most of early 2012 until May, when Cushing glutted to a record 45 MMbbl on the back of a US unconventional boom that pushed production to multi-decade highs. Meanwhile, French and Greek elections with anti-austerity outcomes rattled confidence in the political will necessary to keep Greece from exiting the euro and
defaulting on its substantial debts. WTI broke through its $100 floor to the upper $90s while Brent also dropped from just under $120 to the lower $110s.
US production and middling domestic economic news continued to pressure WTI lower through June when it hit a 2012 low of $77.69/bbl. The eurozone was again the agent of change, pushing WTI up 9.4% in a single day (June 29, to $84.96) on news of a Spanish bank debt repayment/Italian aid deal. This launched a new trading range in the mid- to upper $80s that lasted through July.
Soon after, Israel began threatening action against Iran with or without US help, while 20% Iranian production cuts curtailed supply. A single-day 5% jump to $91.40 August 3 put in a new floor, and WTI traded in the mid- to upper $90s into September. Prices then fell back to the lower $90s on what many called a technical correction, where they stayed until late October when Europe again swung markets. The EU’s failure to reach a major deal after a two-day summit dropped WTI into the upper $80s. Prices stayed there until just recently, despite a brief flare-up between Israel and Hamas-run Gaza.
Raymond James attributes recent price creep above $90 to Mideast tensions and technical trading. Strong US distillate demand also appears to be a contributor. WTI fared well despite fiscal cliff concerns that hammered markets, gaining $0.97 Monday to end 2012 at $92.27.
OIL
Crude forecasts vary on supply & demand Continued From Pg 1
EIA dropped WTI for Brent as a reference price in its annual outlook.
EIA: US crude output hitting 7.5 MMbopd by 2019; at least one estimate doubles that.
WTI closes 2012 down 8% YOY.
New EIA-Long Term Forecasts2025 2035 2040
WTI $115.36 $143.41 $160.68
Brent $117.36 $145.41 $162.68
Henry Hub $4.87 $6.32 $7.83
Source: EIA AEO2013 Early Press Release
Europe was responsible for some of 2012’s largest single-day WTI moves.
Crude Oil (Near Mth Contract Last-2 Wks w/Volatility Index)
Source: NYMEX via www.cmegroup.com
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