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October 20, 2016 • Volume 09, No. 14

MidstreaMNewsServing the marketplace with news, analysis and business opportunities

NORTHERN OHIO SALE PACKAGE339-Producing Wells. 22,266-Net Acres.MAHONING, COLUMBIANA, STARK, PPCARROLL & PORTAGE COUNTIESTarget: Utica ShaleUp To 243 Drilling Locations Available. ~420Avg 93% OPERATED WI; ~81-83% NRI BOEDOct. Net Prod: 207 BOPD & 1,715 MCFDOct. Net Cash Flow: ~$131,450/Month Est. EUR: 140 MBO & 160 MMCFPP 5830DV

SOUTHERN UINTA BASIN ASSETS338-Wells. 29,915-Net Acres (85% HBP).DUCHESNE & --- CARBON COUNTY, UTAH PPPrimary Target: Wasatch-Mesa VerdeSecondary Targets: Wasatch/ Mesa ~50 Verde & Navajo/ Entrada MMCFEDAvg 95% OPERATED WI; 80% NRINet Production: ~49 MMCFED (94% Gas)Forecast Cash Flow: $1,666,667/MonthPDP Reserves: 201 BCFETotal Reserves: 1,066 BCFEPDP PV10: $123,000,000PP 5579DV

DEALS FOR SALE

Rice boosts 2017 throughput 45% via Vantage deal

Rice Midstream Partners is expanding its core Appalachian footprint in Greene and Washington counties, Pennsylvania, with the $600 million purchase of midstream assets associated with parent Rice Energy’s acquisition of Vantage Energy. The new assets boost RMP’s anticipated 2017 throughput by

45% to 1.34 Bcf/d from 925 MMcf/d. RMP will also see a 67% increase in dedicated acreage to 199,000 net acres, which will be one of the largest and most concentrated core dry-gas acreage dedications in the Marcellus, Rice said.

The assets include 30 miles of dry-gas gathering and compression and adds 175-225 million gallons of water throughput for anticipated 2017 volumes of 1.08-1.23 million gallons.

Sunoco buys Permian crude system from Vitol for $760MMSunoco Logistics Partners is growing its Permian Basin presence with the purchase

of commodity trader Vitol’s crude system for $760 million plus working capital. The deal boosts Sunoco’s ownership in the SunVit pipeline, which was a 50:50 JV with Vitol,

to 100%. The system encompasses a 2 MMbo terminal in Midland, Texas, and a gathering and mainline system of more than 100 miles serving an

unnamed, investment-grade Midland Basin producer. Sunoco will also own all of Vitol’s marketable crude inventory in the basin.

SunVit is a 40-mile, 20-in. crude line that runs from the storage hub in Midland to Garden City, where it connects to Sunoco’s Permian Express 2 pipeline. “The Vitol pipeline assets are located in what we believe are the three best counties in the Midland Basin,” said President and CEO Michael Hennigan. “Adding a 2 MMbbl terminal in Midland is very complementary to our Permian strategy.” Closing is expected in Q4.

In conjunction with the deal, Energy Transfer, which owns Sunoco Logistics’ general partner, will reduce the partnership’s incentive distributions to the general partner by $60 million over two years beginning in 3Q16. Hennigan said the partnership appreciated the savings.

Crestwood, First Reserve expand in Delaware BasinCrestwood Equity Partners and private equity firm First Reserve entered

into a long-term agreement to construct, own and operate a gas-gathering system in Reeves, Loving and Ward counties, Texas, through their Delaware Basin

joint venture to serve Shell subsidiary SWEPI. The system will encompass 194 miles

of low-pressure gathering line and 36 miles of high-pressure trunkline. Initial capacity will be 250 MMcf/d. The system will also include centralized compression facilities. Shell intends to dedicate 100,000 acres to the system, which is expected in service by July 2017.

The $180 million project is underway. Under the agreement, Shell can purchase 50% equity in this system before Sept. 1, 2017. The 50:50 JV is structured so that the PE firm funds 100% of initial capital outlay with Crestwood funding the remaining costs.

Phillips 66 drops down $1.3 billion in assets to MLPIn the largest dropdown to date from Phillips 66 to its MLP, Phillips 66 Partners

will acquire 30 crude, refined-products and NGL assets housed in four systems across the country for $1.3 billion. The assets feed and provide takeaway from Phillips 66

refineries in Billings, Montana; Ponca City, Oklahoma; Borger, Texas; and New Jersey. The deal

consideration reflects an 8.7x multiple of the assets’ anticipated $150 million 2017 EBITDA. Chairman and CEO Greg Garland said, “We remain committed to maintaining a stable, fee-based, growing business model at Phillips 66 Partners and are on track to deliver on our commitment to a five-year distribution compound annual growth rate of 30% through 2018.”

In the Billings system, the partnership is getting 79% operated interest in the 623-mile, 126,000 bo/d Glacier crude pipeline from Cut Bank on the Canadian border to the Phillips 66 Billings refinery. Two associated storage terminals at Buffalo and Billings combine for 570,000 bo.

Deal includes 3,500 miles of crude, products and NGL pipeline.

194-mile, 250 MMcf/d system to serve Shell subsidiary SWEPI.

Buy boosts stake in SunVit to 100%; includes 2 MMbo in storage.

$600MM buy adds 30 miles of gas gathering, compression.

Continues On Pg 4

Continues On Pg 11

Continues On Pg 6

Continues On Pg 8

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MidstreaMNews 2 October 20, 2016

MPLX flowing condensate on Cornerstone pipeline

MPLX’s Cornerstone pipeline is now transporting condensate in Ohio. The 50-mile, 16-in. line ships Utica liquids from MPLX sub MarkWest Energy Partners’ Cadiz complex and Williams and M3 Midstream’s Utica East Ohio processing facility in Harrison County. About 50,000 bbl/d is currently flowing, but the system has total capacity for 180,000 bbl/d. Cornerstone is one of the Utica’s first batched pipelines.

The 16-in. portion of the line ends at an East Sparta, Ohio, storage facility and from there continues as an 8-in. line with 45,000 bbl/d capacity to parent Marathon Petroleum’s refinery in Canton. The pipeline will cut down on the number of truck shipments to the East Sparta facility. Cornerstone will also eventually be linked to MarkWest’s Hopedale fractionator in Harrison County east of the pipeline’s current origin point.

Pipelines Inventories

Change in Lower 48 Natural Gas Storage

-350

-300

-250

-200

-150

-100

-50

0

50

100

150

200

Jan

Feb

Mar

Ap

r

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

5 Yr Range 5 Yr Avg 2015 2016

Source: OTC Global Holdings Market Data and EIA

Current US Petroleum Stocks by Type (MMbbl)For Weeks Ending

10/14/16 10/7/16 Net Change 10/16/15

Crude Oil (Excluding SPR) 468.7 474 -5.30 444.6

Motor Gasoline 228 225.5 2.50 219.8

Distillate Fuel Oil* 155.7 157.0 -1.30 145.0

All Other Oils 488 487.6 0.40 467.1

Crude Oil in SPR 695.1 695.1 0.00 695.1

Total 2,035.5 2,039.2 -3.70 1,971.6 *Distillate fuel oil stocks located in the “Northeast Heating Oil Reserve” are not included.Note: Data may not add to total due to independent rounding.Source: EIA Weekly Petroleum Status Report

Current Natural Gas Stocks by Region (Bcf)

10/14/16 10/7/16Net

Change 6/24/15

% Change

YOY

% Diff. From 5-Yr

Avg.

East Region 925 913 12 894 3.5 2.9%

Midwest Region 1,093 1,071 22 1,037 5.4 5.3%

Mountain 243 240 3 212 14.6 19.1%

Pacific 325 323 2 367 -11.4 -8.5%

South Central 1,250 1,212 38 1,279 -2.3 8.3%

Total Lower 48 3,836 3,759 77 3,789 1.2 5.1%

Source: Energy Information Administration: Form EIA 912, “Weekly Underground Natural Gas Storage Report” and the Historical Weekly Storage Estimates Database. Row and column sums may not equal totals due to independent rounding.

US gas stocks rose by 77 Bcf for the week ended Oct. 14. Inventories are 5.1% above the five-year average and 1.2% above this time last year.

MidstreamNews is published every three weeks by PLS Inc.

PLS MidstreamNews covers the midstream, downstream and LNG sector that news and analysis Topics include gathering, marketing, pipelines, mergers, acquisitions, capital capital financing.

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Volume 09, No. 14 3 iNfrastructure

EQM to grow Marcellus transmission line, gathering systemsEQT Midstream Partners (EQM) acquired a Marcellus transmission pipeline

and four gathering systems in a $275 million dropdown from parent EQT that are expected to be immediately accretive. EQM paid for the cash deal through borrowings under its revolver; the effective date is Oct. 1. Plans are already in place for expansions of both the transmission line and gathering systems.

The assets include the Allegheny Valley Connector (AVC) pipeline and storage system, which encompasses 209 miles of pipeline that transports 450 MMcf/d from southwestern Pennsylvania into West Virginia and includes 11 Bcf in working gas storage. EQT acquired the system from Pennsylvania gas distributor Peoples Natural Gas in 2013, and the

utility is fully contracted for winter seasons through 2034.

As for the gathering assets, they encompass four systems combining for 87 miles, 370 MMcf/d of capacity and 7,000 hp of compression. The systems are Applegate, McIntosh and Terra in Pennsylvania and Taurus in West Virginia. EQT is under a 10-year firm capacity commitment for 235 MMcf/d on the systems.

Plans are already in place to expand both AVC and the four gathering systems. EQM said it would spend $50 million on growth projects related to the system this year and next. It expects AVC to grow its EBITDA to $35 million in 2018 from $31 million next year. For the gathering systems, growth projects will total $105 million to add 20 miles of line and 20,000 hp of compression over four units. Upon completion of the expansion, EQT will commit to 365 MMcf/d of firm capacity. The gathering systems’ EBITDA is anticipated to nearly double in 2018 to $30 million from an expected $16 million next year.

Ohio Valley Connector now shipping 650 MMcf/d EQT Midstream Partners has started service on its Ohio Valley Connector

(OVC) pipeline. The 37-mile line extends the company’s Equitrans system, linking Wetzel County in northern West Virginia to Clarington, Ohio, in Monroe County. There,

OVC connects to EQT’s Equitrans mainline and Sunrise Transmission System as well as Tallgrass Energy’s REX pipeline. Interconnects are also planned with

Spectra’s Texas Eastern Transmission and Energy Transfer’s Rover pipelines.

OVC has a 20-year service agreement in place with EQT for 650 MMcf/d, but FERC has approved total capacity of 850 MMcf/d for the line. The company expects to accept full nominations for the pipeline soon. The project also comprised two new compressors with 40,000 hp combined—the Corona station in Wetzel County and the Plasma station in Monroe County.

The $130 million OVC project was part of a multi-year, multi-project plan to expand Marcellus and Utica gas transportation. In addition to the Ohio-to-West Virginia pipe, EQT will also spend $145 million to upgrade its other regional pipeline systems: including the Jupiter gathering system in Greene and Washington counties, Pennsylvania.

Pipelines Multitude of acquisitions and divestments dominate cycle

In the biggest deal of this issue of MidstreamNews, Phillips 66 dropped down crude and refined-products assets in four systems to its MLP in a deal

worth $1.3 billion (page 1). Another dropdown saw EQT Midstream (EQM)

acquire a Marcellus transmission pipeline and four gathering systems from its parent EQT for $275 million (page 3). Sanchez Production Partners bought parent Sanchez Energy’s remaining interest in the South Texas Carnero Gathering and Processing JV (page 9). Offshore, Shell Midstream paid $350 million for two pipeline interests from parent Shell (page 8).

In other news, DTE made an acquisition in the Marcellus, paying $1.3 billion

for two pipeline interests (page 4). As part of Enbridge’s ongoing efforts to right-size its portfolio in the wake of its Spectra buy, Tundra Energy Marketing Ltd. bought Enbridge’s South East Saskatchewan pipeline for $819 million (page 9).

West Texas remains the center of US onshore action. Crestwood will build a new gas-gathering system for Shell subsidiary SWEPI (page 1) as part of the pair’s Delaware Basin JV launched a year ago. Sunoco Logistics Partners is growing in the Permian as well, as it bought Vitol’s crude system for $760 million (page 1). In Appalachia, Rice Midstream expects to expand throughput by 45% in 2017 as part of its parent’s acquisition of fellow driller Vantage Energy.

In project news, MPLX (page 2) and EQM (page 3) started up systems in the Eastern region while Williams Partners faced yet another delay with the Atlantic Sunrise pipeline (page 7). In Canada, SemCAMS inked a deal with NuVista to build a 200 MMcf/d gas plant at Wapiti (page 7).

Midstream routes out of the Bakken, however, are seeing setbacks beyond the delay of Dakota Access. Two oil-by-rail plans met with local governing opposition while Shell shut down a proposal to build a rail terminal in Anacortes, Washington (page 6).

IN THIS ISSUE 37-mile line approved for 850 MMcf/d

total capacity by FERC.

Allegheny Valley Connector transports 450 MMcf/d over 209 miles.

Gathering systems move 370 MMcf/d through 87 miles of pipe.

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MidstreaMNews 4 October 20, 2016

DTE expands in Appalachia through $1.3B deal

DTE Energy built Appalachian midstream scale in late September when it acquired pipeline interests for $1.3 billion. The deal included M3 Midstream’s 100% interest in the Appalachian Gathering System (AGS) and 40% interest in the Stonewall pipeline. DTE also bought another 15% of Stonewall from Vega Energy Partners for a majority stake in the line. The pipelines offer connectivity to two DTE gas pipeline projects underway.

AGS begins in Washington County, Pennsylvania, and travels 150 miles south into West Virginia to terminate in Harrison County, where Stonewall originates. Not much background is offered on AGS, but 2015 news reports indicated Stonewall was essentially spun off from AGS and built out 67 miles to Lewis County, where it links up with Columbia Gas Transmission. The pipeline can ship 1.4 Bcf/d. The assets can also connect with Texas Eastern Transmission and NEXUS Gas Transmission—both joint projects of DTE and Spectra.

“These transactions will significantly increase our midstream presence in the Appalachian Basin,” said CEO Gerry Anderson. “The acquired assets are in a productive area of the Southwest Marcellus/Utica region and have expansion potential. These acquisitions align with DTE’s existing strengths in managing natural gas midstream assets.”

Closing is expected in Q4. Wells Fargo Securities served as financial adviser to DTE, and Wells Fargo Bank NA provided financing.

A&D

The system also includes the 342-mile, 33,000 bbl/d Seminoe products pipeline that offers takeaway from the refinery into Wyoming. Two products terminals at Sheridan and Casper, Wyoming, combine for 386,000 bbl of storage.

The Ponca City system includes 503 miles of crude pipeline feeding the refinery: the North Texas Gathering system in Wichita Falls (224 miles; 28,000 bo/d), the Oklahoma Crude pipeline from Wichita Falls to Ponca City (217 miles; 100,000 bo/d); and the CushPo pipeline from

the Cushing hub to Ponca City (62 miles;

130,000 bo/d). Terminals in Ponca City, Cushing and Wichita Falls combine for 1.7 MMbo in storage. An associated products takeaway system includes 524 miles over four pipelines: Cherokee East (287 miles; 55,000 bbl/d); Cherokee North (105 miles; 83,000 bbl/d); Cherokee South (90 miles; 46,000 bbl/d); and Medford (42 miles; 10,000 bbl/d). Seven terminals combine for an associated 1.7 MMbbl in

products storage.The Borger crude system

encompasses 1,089 miles to feed the refinery: the West Texas Gathering system (287 miles; 115,000 bo/d); Line WA (289 miles; 104,000 bo/d); Line 80 (237 miles; 28,000 bo/d); and Line O (276 miles; 37,000 bo/d). A terminal in Buxton, Oklahoma, holds 400,000 bo. Varied interests in products takeaway lines include: 100% in the operated Borger-to-Amarillo line (93 miles; 76,000 bbl/d); 33% and 54% interests in respective 102-mile and 19-mile segments of the 121-mile Amarillo-to-Lubbock line (33,000 bbl/d); and 50% interest in the Amarillo-to-Albuquerque line (293 miles; 34,000 bbl/d). Terminals in Amarillo, Lubbock and Albuquerque combine for 700,000 bbl in storage.

The Bayway assets include a terminal in Linden, N.J. and Tremley Point and 2.0 MMbbl of storage. The deal includes a 10-year terminaling and throughput agreement under which Phillips 66 will commit to at least 85% of forecasted volumes on the systems.

Phillips 66 Partners will fund this acquisition with debt and $196 million netted from new partnership units issued to Phillips 66, which will be split proportionally between common and general partner units to allow Phillips 66 to maintain its 2% general partner interest. Closing is expected in October, at which time the partnership can receive cash earnings associated with the assets dated to Oct. 1.

Pipelines

Phillips 66 drops down $1.3B in assets Continued From Pg 1

Systems serve Montana, Oklahoma, Texas, New Jersey refineries.

10-year agreement in place with 85% MVC commitment from parent.

DTE buys 100% in Appalachian Gathering System, 55% in Stonewall.

Regional Oil & Gas Intelligence November 10, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 02, No. 15

Deals For Sale

MERCER CO., OH PROSPECT10,000-Contiguous Acres.SHALLOW TRENTON DVHISTORICAL OIL PLAYShallow Trenton Blanket. 1,100 Ft.100% OPERATED WI AVAILABLETERMS NEGOTIABLE TRENTONCONTACT LEASE OWNER FOR INFODV 3012L

WESTERN PA MARCELLUS LEASE417-Acres.EXCO NOT RENEWING LARMSTRONG COUNTYAvailable Due to Vertical Pugh Clause.Includes Burkett & Utica Shale. MARCELLUS/GROUND FLOOR OPPORTUNITY UTICANRI And Terms Are Negotiable.L 6947

No Commission. Call 713–650–1212

All Standard Disclaimers & Rights Apply.

Gulfport cutting back on eastern Ohio productionIn its Q3 results update, Gulfport

Energy announced it is cutting 100 MMcf/d, or ~15%, of its Utica shale production in Ohio until early 2016. The company hopes gas prices will rise and says it will save $500,000/well by not fracking this winter.

Gulfport says it has scrapped its plans to add a fifth rig to its Utica program and will instead continue to run four. A fracking crew will also be idled.

The company drilled 15 Utica wells in Q3 and began production on 16 more, and it dropped drilling costs 5-8%. Last month, Gulfport entered into a Utica shale JV with Rice Energy for a dry gas gathering

system. The project, in which Gulfport has a 25% stake to Rice’s 75%,

includes the system with a capacity of more than 1.76 Bcf/d and more than 165 miles of pipelines with multiple connections to interstate lines, 50,000 horsepower of compression for gathering and delivery, and a fresh water distribution system.

EQT encouraged by ongoing deep Utica resultsJust a few months after bringing its

record-breaking dry gas Utica well online, EQT Corp. is banking on the play as a potential paradigm shifter. The company has suspended drilling outside of its core area in southwestern Pennsylvania and West Virginia to switch its focus to wells with the highest returns.

Back in July, EQT tested the Scotts Run #591340 in Greene County, Pennsylvania, at a 24-hour rate of 72.9 MMcf/d. Reservoir modeling suggests an EUR of 4.3-5.9 Bcf

per 1,000 ft of lateral for the Scotts Run well. The company says that at present, the well is flowing into the sales pipeline at a choke-restricted rate of 30 MMcf/d.

“A year ago, it would have been hard to imagine a more prolific play than the Marcellus. However, if the deep Utica works, it is likely to be larger than the Marcellus over time,” CEO David Porges said on EQT’s Q3 earnings call.

Will no longer be adding a fifth rig to Utica; will continue running four.

Regional Activity (State Data)(10/05/15 to 11/04/15)

Compls PermitsIllinois – 23Indiana – 9Kentucky – 31New York – 2Ohio – 78Pennsylvania – 166Tennessee – 4West Virginia 51 53

Most Active Operators by Permits➊ EQT Production 27➋ SWN Production 24➌ Titusville O&G 20

Permits by Formation (by Last Scout)

Formation 11/10 10/20 09/28Marcellus 25 27 32Clinton 19 20 17Utica/Point Pleasant 18 48 31Knox GP 17 16 4Point Pleasant 17 24 11St Louis 10 4 2Trenton 9 4 2Warsaw 6 3 4Aux Vases 4 3 2Other Formations 241 260 237TOTAL 366 409 342Source: Illinois DNR, Indiana DNR, KYDOG, NYSDEC, ODNR, PADEP, TDEC & WVDEPActive Rigs Running (Baker Hughes) 68

Continues On Pg 14

Well tested at 72.9 MMcf/d flowing to sales at choke-restricted 30 MMcf/d.

Dry Gas Utica - Top Wells

Well Name County OperatorPeak Rate (MMcfe/d)

Peak Rate (boe/d)

Lateral Length Stages

Scotts Run Greene, PA EQT 72.9 12,150 3,221 N/A

Claysville Sportsman 11H Washington, PA RRC 59.0 9,833 5,420 N/A

Stewart Winland 1300U Tyler, WV MHR 46.5 7,750 5,289 22

Bigfoot #9H Belmont, OH RICE 41.7 6,948 6,957 40

Yontz 1H Monroe, OH AR 38.9 6,483 5,115 N/A

Blake U-7H Marshall, WV GST 36.8 6,133 6,617 N/A

Stalder #3UH Monroe, OH MHR 32.5 5,417 5,050 20

Rubel 1H Monroe, OH AR 31.1 5,183 6,554 N/A

Rubel 2H(2) Monroe, OH AR 30.9 5,150 6,571 N/A

Irons #4H Belmont, OH GPOR 30.3 5,050 6,629 23

AVERAGE 42.1 7,010 5,742 26.25

Source: Magnum Hunter Resources October 15, 2015 via PLS docFinder (www.plsx.com/finder)

EASTERN SCOUT

Discover which Appalachian areas are seeing the most activity.

EasternScout

All Standard Disclaimers & Seller Rights Apply.

January 13, 2015 • Volume 08, No. 02

CapitalMarketsServing the marketplace with news, analysis and business opportunities

NORTH TEXAS SALE PACKAGE 18-Wells. ~4,000-Gross Acres.PARKER, JACK & ERATH COUNTIESBig Saline, Marble Falls, Atoka Sand, PP-- & Conglomerate Reservoirs.Behind-Pipe Potential In Each WellAdditional Barnett Shale PotentialAll Acreage HBP. 18 Leases. 19275-100% Operated WI; 80% Lease NRI MCFDGross Production: 271 MCFD & 33 NGLsNet Production: 192 MCFD & 23 NGLPP 3426DV

KERN CO., CA PROPERTY ~18,000-Contiguous Net Acres.BEER NOSE FIELDBloemer Tight Sandstone Objective. PPEstimated Depth: 10,000-15,000 Ft.Also Monterey, Belridge, Gibson, Oceanic,Santos, Tumey & Kreyenhagen Potential. TIGHT100% OPERATED WI; ~77% NRI SANDGross Production: 36 BOPD & 57 MCFDNet Production:27 BOPD & 44 MCFD6-Mn Avg. Net Cash Flow: ~$28,800/MnPP 5217DV

FEATURED DEALS

Rice Midstream IPO raises $474MM in tough market

After a fairly banner 2014 for energy IPOs on the whole but a significant dry spell for all segments other than midstream through the last few months of the year, Rice Energy put a nice bow on 2014 with its buzzer beater Rice Midstream Partners IPO. Rice sold 28.75 million units at $16.50, for total gross proceeds of $474.4 million, and $441.6 million net. Units priced 17.5% below the midpoint of the

targeted price range of $19-$21/unit, probably reflecting the challenges the energy sector has seen of late in terms of obtaining financing. However, in an interesting turn for an underpriced IPO, subsequent demand was strong enough to merit full exercise of a 3.75 million unit option (included in the above gross proceed total) which boosted proceeds by $61.9 million.

Upstream MLPs under fire as distributions cut Upstream MLPs have been the subject of much discussion of late as a particularly

at-risk segment of the energy patch, and these concerns have in fact been realized for at least some partnerships with distribution and capex cuts. MLPs in general have been favored for their bond-like, high-yield distributions, stemming from preferential tax treatment for reinvesting a high percentage of profits back into the business. However, they also generally rely heavily on debt to fuel growth. And unlike their midstream brethren which are better positioned to weather recent commodity volatility with long-term, fixed-price contracts, upstream MLPs face full exposure to the recent oil and gas price declines, except to the degree they make use of hedges. However, hedges will largely peel off over the course of the year, and many of these partnerships will soon face the difficult decision of using cash to cover interest requirements and maintaining what may have become unsustainable payouts, or slashing the distributions which drew investors to them in the first place so they can make debt levels more reflective of current economics.

Concho dials capex back $1.0 billion in second look In a rather noteworthy example of what many companies which announced 2015

spending plans early are dealing with these days, Concho Resources revised its capex for this year to more accurately reflect current market conditions. In early November

when WTI was still trading above $78/bbl, Concho had announced a $3.0 billion 2015 budget targeting ~30% production growth, but warned that it would ease spending if oil prices didn’t firm up over the next few months.

With oil now near $45, that clearly hasn’t happened, and Concho has proceeded accordingly with a new $2.0 billion plan which is 33% lower than prior guidance and down 23% YOY vs. 2014’s $2.6 billion.

The new plan contemplates $1.8 billion in D&C spend (down 33% from the prior $2.7 billion), with ~$1.3 billion or 72% of spend targeting the Delaware Basin (down 25% vs. prior budget, up from 64% of total spend), $300 million or 17% targeting the Midland Basin (down 49% vs. prior budget and 22% of total) and the remaining $200 million or 11% targeting the New Mexico Shelf (down 47% from prior budget and 14% of total).

Southwestern plans multibillion equity raise to fund buys The implications of Southwestern Energy’s $4.98 billion acquisition of West

Virginia and southwest Pennsylvania assets from Chesapeake Energy (plus another $394 million in add-ons in the region from Statoil) are beginning to become apparent for the company, with impacts on both Southwestern’s capital structure and capex.

The company is finally providing a clearer picture of how it plans to permanently fund the Chesapeake deal. The acquisition was funded

at closure with a $4.5 billion bridge loan and a two-year $500 million unsecured term loan, but significant sums of longer-term debt and equity were clearly needed.

In line with its previously announced intentions, Southwestern announced a proposed equity sale which should raise $1.8- $2.1 billion, depending on whether options are exercised. Specifically, the company plans to sell 20.26 million shares of common with a 3.04 million share option, and 26 million depositary shares (each amounting to a 1/20th interest in Series B mandatory preferred shares) with 3.9 million shares in possible options.

Should raise $1.8-$2.1 billion in equity depending on whether options go.

Boosting focus on Delaware Basin from 64% of prior budget to 72%.

Upstream MLPs are choosing between debt loads & distributions.

Units priced 17.5% below midpoint at $16.50 but option fully exercised.

Continues On Pg 4

Continues On Pg 6

Continues On Pg 8

Continues On Pg 14

Phillips 66 Partners issues notes offering for asset buy.

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A new database that tracks financings, banking relationships and associated fees.

Call 713-650-1212 or email info@plsx.com. www.plsx.com/capitalize

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Volume 09, No. 14 5 iNfrastructure

Phillips 66 Partners Acquires $1.3B in Assets from Parent Source: www.phillips66partners.com

Asset Interest Location Miles Size Capacity (bbl/d)

Storage (bbl)

Billi

ngs Cr

ude Glacier pipeline 79% Cut Bank, Mont. to Billings 623 8", 10", 12" 126,000

Buffalo Crude Terminal 100% Montana 300,000

Billings Crude Terminal 100% Montana 270,000

Prod

ucts Seminoe pipeline 100% Billings to Sinclair, Wyo. 342 6-10" 33,000

Sheridan Terminal 100% Sheridan, Wyo. 15,000; 2 bays 86,000

Casper Terminal 100% Casper, Wyo. 5,000; 2 bays 300,000

Ponc

a Ci

ty

Crud

e

Oklahoma pipeline 100% W. Falls to P. City 217 12" 100,000

CushPo pipeline 100% Cushing to P. City 62 18" 130,000

North Texas Gathering System 100% Wichita Falls area 224 2-16" 28,000

Ponca City Terminal 100% Oklahoma 1.2 MM

Cushing Terminal 100% Oklahoma 300,000

OK Crude PL Terminal 100% Wichita Falls 240,000

Prod

ucts

Cherokee East pipeline 100% Medford to Mt. Vernon, Mo 287 10-12" 55,000

Cherokee North pipeline 100% P. City to Ark. City/Wichita 105 8-10" 83,000

Cherokee South pipeline 100% P. City to Oklahoma City 90 8" 46,000

Medford pipeline 100% P. City to Medford 42 4-6" 10,000

Glenpool Terminal 100% Oklahoma 19,000; 2 bays 627,000

Mt. Vernon Terminal 100% Misssouri 46,000; 4 bays 363,000

Mt. Vernon NGL Terminal 100% Missouri 10,000; 2 bays 96,000

Ponca City Terminal 100% Oklahoma 23,000; 2 bays 51,000

Ponca City NGL Terminal 100% Oklahoma 10,000; 2 bays 0

Wichita South Terminal 100% Kansas 0 255,000

OKC Products Terminal 100% Oklahoma 48,000; 4 bays 352,000

Borg

er

Crud

e

Line O 100% Cushing to Borger 276 10" 37,000

Line 80 100% Gaines to Borger 237 8", 12" 28,000

Line WA 100% Odessa to Borger 289 12", 14" 104,000

West Texas Gathering System 100% West Texas 287 various 115,000

Buxton Crude Terminal 100% Oklahoma 400,000

Prod

ucts

Borger Amarillo pipeline 100% Borger to Amarillo 93 8-10" 76,000

SAAL pipeline 33% Amarillo to Abernathy 102 6" 33,000

SAAL pipeline 54% Abernathy to Lubbock 19 6" 30,000

ATA pipeline 50% Amarillo to Albuquerque 293 6-10" 34,000

Albuquerque Products Terminal 100% New Mexico 18,000; 3 bays 244,000

Lubbock Products Terminal 100% Texas 17,000; 3 bays 179,000

Amarillo Products Terminal 100% Texas 29,000; 5 bays 277,000

Bayw

ay

Prod

ucts Tremley Point 100% New Jersey 39,000; 3 bays 1.593 MM

Linden 100% New Jersey 121,000; 9 bays 429,000

To learn more about PLS, call 713-650-1212Find more on the midstream sector at

MidstreaMNews 6 October 20, 2016

IEnova buys out Pemex in Mexican infrastructure JVSempra Energy’s Mexican subsidiary, IEnova, now owns 100% in Gasoductos

de Chihuahua, having acquired Pemex Transformación Industrial’s 50% equity interest in the JV for $1.14 billion. Pemex will keep 50% shareholder interest in the Ramones II Norte pipeline project through Ductos y Energéticos del Norte, S.de R.L. de C.V. The JV includes three gas pipelines, an ethane pipeline, an LPG pipeline and a storage terminal.

The deal was announced in summer 2015.

Gasoductos de Chihuahua owns a 23-mile, 24-in. pipeline that transports 100 MMcf/d from the US-Mexico border to the Samalayuca power plant; a 71-mile, 36-in. bidirectional pipeline that flows 1 Bcf/d within the state of

Tamaulipas, a 72-mile, 48-in. pipeline under construction that will flow 1 Bcf/d from an interconnection with the

Agua Dulce pipeline at the US/Mexico border in Tamaulipas to a Pemex measuring station in Nuevo Leon; a 118-mile, 12-in. LPG line with a 42,000 bbl/d delivery capacity from Pemex’s Burgos gas-processing facility to a facility in Monterrey; and an LPG storage facility in Jalisco with four tanks aggregating 56,000 bbl of capacity.

IEnova has invested more than $4 billion into Mexican infrastructure. Most recently, the company formed a JV with TransCanada to fund $800 million of the $2.1 billion Sur de Texas-Tuxpan gas line, transporting 2.6 Bcf/d from the Texas Gulf Coast to the coastal city of Tuxpan, Veracruz, for state-owned utility Comisión Federal de Electricidad.

“With First Reserve’s support and incremental capital commitment to the JV, Crestwood is very well-positioned financially to execute on the SWEPI opportunity and other midstream opportunities in the Delaware Basin, including the previously announced

three-stream gathering system in Reeves, Loving and Culberson counties, which remains under exclusivity with an anchor shipper,” said

Crestwood CEO Robert Phillips.The pair formed the JV with a $500 million commitment to pursue Delaware Basin

infrastructure projects. Their first project is the 164-mile crude and condensate system Phillips mentioned. That 200,000 bbl/d system is slated to be operational by 2Q17 and has secured an anchor shipper.

Western Gas Partners, SWEPI also teaming up—Anadarko MLP Western Gas Partners (WES) has also made a midstream

agreement with SWEPI. The MLP will gather and process gas in the Delaware Basin for Shell for a minimum of 20 years. The contract adds another producer to WES’ portfolio, which includes midstream assets in the Rockies, Midcontinent,

Appalachia and Texas. “I am very pleased to announce that

we have entered into a new long-term relationship with Shell, a significant producer and acreage holder in the prolific Delaware Basin,” said CEO Donald Sinclair. “This agreement enables us to provide midstream services to another top-quality producer in the region as we continue to expand our best-in-class gathering and processing footprint in West Texas.”

Pipelines

Crestwood, First Reserve expand Continued From Pg 1

$180MM system will have expected capacity of 250 MMcf/d.

Western Gas Partners adds SWEPI to customer list, too.

Sempra sub pays $1.14 billion for 50% equity interest.

Assets include ethane, LPG line & storage terminal.

Bakken midstream options take hit, oil-by-rail plans fail

Midstream routes out of the Bakken have had a rough go lately. While the Dakota Access pipeline, which could carry more than half of North Dakota’s oil to the Gulf Coast, remains stalled, landlocked Bakken producers have also seen three crude-by-rail plans on the West Coast either be abandoned or rejected.

Shell has abandoned a plan to build a train terminal to feed its Anacortes, Washington, refinery. The company would have imported 400,000 bo per week via six trains, each with 102 cars, but said the project is uneconomic in the current market.

Two additional proposals in California have been shot down by local governing bodies, and it isn’t clear what the next steps are. Phillips 66 may appeal a San Luis Obispo Planning Commission decision to reject its plan to receive three 80-car trains per week to supplement heavy-crude shortages at its Santa Maria refinery. In Benicia, California, the City Council has rejected a similar proposal by Valero, but the company says the city is violating state and federal law regarding due process. The proposal calls for Valero to receive two 50-car trains per week to its refinery there.

North Dakota produced 1.03 MMbo/d during July, according to preliminary numbers from the state pipeline authority, which was a slight uptick of 2,376 bo/d from June’s official total. Of that, 59% leaves the state via pipeline and 32% by rail. While prices are low and Bakken producers are holding off, midstream options aren’t as crucial. However the recent price elevation to more than $50 a barrel may change that, as operators dig into the states 700-well DUC inventory.

Developments & Trends

Shell backs out of 400,000 bo per week plan, citing economics.

Regional Oil & Gas Intelligence November 3, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 02, No. 14

MUSSELSHELL CO., MT ACREAGE77,413-Gross & 52,200-Net Acres.CENTRAL MONTANA UPLIFT LMISSISSIPPIAN HEATH OIL PLAYProposed Depths: 3,600-9,675 Ft. HEATH100% OPERATED WI FOR SALE SHALEOffset Production: ~100 BOPDL 3185DV

SHERIDAN CO., MT PROSPECTS10-Potential Wells. 3-Prospects.WILLISTON BASIN DVMULTIPAY PROSPECTSRed River. 11,300 Ft.Mission Canyon & Others. 7,500 Ft.60% OPERATED WI; 48% NRI MULTIPAYExpected IP (Red River): 375 BOPDWell Reserve: 300 MBOE/Well DV 3851

Deals For Sale

No Commission. Call 713-650-1212

All Standard Disclaimers & Rights Apply.

BAKKEN SCOUT

Regional Activity (State Data)(10/08/15 to 10/29/15)

Compls Permits

North Dakota 25 136

South Dakota – –

Montana – 2

Most Active Operators by Permits

➊ EOG Resources 32

➋ Continental Resources 21

➌ QEP Energy 12

Permits by Formation (by Last Scout)

Formation 11/03 10/13 09/22

M Bakken 12 16 9Three Forks B2 10 3 1Three Forks B1 7 9 13Bakken 3 7 7Three Forks B3 2 2 1Cut Bank 1 – –Duperow 1 – –Three Forks B4 1 – –Other Formations 101 78 111TOTAL 138 115 142Sources: MBOGC, NDIC & SDDNR

Active Rigs Running (Baker Hughes) 63

Statoil long lateral flows at 3,486 boe/d from the BakkenInternational player Statoil flowed a

long-lateral Bakken well at 3,071 bo/d and 2,489 Mcf/d (3,486 boe/d, 88% oil). The Heen 26-35 #7H was drilled with a 9,604 ft lateral in Todd field in Williams County, North Dakota.

Two other Statoil completions in Williams County, the Smith Farm 23-14 #6TFH and #7H, are also long laterals drilled in Cow Creek field. The #6TFH targets the Three Forks with a 10,560-ft lateral and

flowed at 2,369 bo/d and 2,735 Mcf/d (2,825 boe/d, 84% oil) and the #7H has a 10,313-ft lateral targeting the Bakken, flowing 2,285 bo/d and 2,508 Mcf/d (2,703 boe/d, 85% oil).

Statoil’s Bakken assets include 330,000 net acres with an extensive gathering system for transportation and resource marketing.

Has 330,000 net acres in the play along with gathering system.

Continues On Pg 3

Top 20 Statoil Williston Basin Completions (01/15/15 - 09/25/15)

County Operator Well Name Field Reservoir TD boe/d Oil %McKenzie Statoil Johnston 7-6 #4H Banks Bakken 22,420 5,129 75%Mountrail Statoil Bures 20-29 #5H Alger Bakken 20,610 4,354 85%Mountrail Statoil Bures 20-29 #6TFH Alger Three Forks 20,646 4,047 86%Williams Statoil Judy 22-15 #5H East Fork Three Forks 20,720 3,894 86%Williams Statoil Hawkeye 16-21 #3H Todd Bakken 21,281 3,884 89%McKenzie Statoil Maston 34-27 #5TFH Banks Three Forks 20,775 3,791 76%Mountrail Statoil Bures 20-29 #3H Alger Bakken 20,254 3,759 86%Williams Statoil East Fork 32-29 XE #1H East Fork Bakken 19,985 3,726 87%Williams Statoil Folvag 5-8 XE #1H Stony Creek Bakken 20,765 3,686 87%Williams Statoil Heen 26-35 #7H Todd Bakken 20,310 3,486 88%Williams Statoil Irgens 27-34 #5H East Fork Bakken 20,350 3,399 82%Williams Statoil Irgens 27-34 #3H East Fork Three Forks 10,830 3,295 83%Williams Statoil Judy 22-15 #3H East Fork Three Forks 20,990 3,260 85%McKenzie Statoil Maston 34-27 #6H Banks Bakken 21,415 3,143 71%Williams Statoil East Fork 32-29 #6TFH East Fork Three Forks 10,699 3,065 87%Williams Statoil Field Trust 7-6 #4H Todd Bakken 20,442 2,893 90%Williams Statoil Smith Farm 23-14 #6TFH Cow Creek Three Forks 21,235 2,825 84%Williams Statoil Folvag 5-8 #6TFH Stony Creek Three Forks 20,824 2,774 88%Williams Statoil Smith Farm 23-14 #7H Cow Creek Bakken 20,925 2,703 85%Williams Statoil Folvag 5-8 #5H Stony Creek Bakken 20,820 2,656 87%Source: North Dakota Industrial Commission

SM reports efficiency gains despite delaying completionsIn the Bakken/Three Forks, SM

Energy production increased 27% YOY in Q3 but dropped 7% sequentially to 22,200 boe/d (85% oil) as the company increased its completion backlog to 47 wells. The company reported that it has

reduced drilling times to 15-21 days—down by 11% vs. 2014—and has drilled several Divide County wells in fewer than 10 days. Overall costs are down 20-25% vs. 2014. Furthermore, enhanced completions including plug-and-perf

with cemented liners are driving 20-30% increases in recoveries per well.

SM has been adding Bakken resources to its Three Forks inventory, and nine

Middle Bakken wells are performing above its Three Forks type curve. Two

additional recently completed wells could extend SM’s Divide County Bakken footprint farther south.

The company also recently announced the opening of a new office in Williston, North Dakota that SM calls a “tangible indication” of its commitment to growing its North Dakota operations.

Drilling times down by 11% & costs down 20-25% vs. 2014.

Continental looks to bright future in the Bakken.

Bakken Scout October 11

A&D

IEnova building 2.6 Bcf/d pipeline with TransCanada.

Access PLS’ archive for previous midstream newsFor general inquiries, email info@plsx.com

Volume 09, No. 14 7 iNfrastructureA&D

NGL Energy takes on Point Comfort storage project

NGL Energy Partners took over a Gulf Coast crude and condensate terminal project in an effort to expand its footprint

there. NGL acquired the assets at Point Comfort,

Texas, from Pelorus for an undisclosed value. The facility will house 350,000 shell barrels of storage, several truck-unloading bays and three docks from which it will load both inland and ocean-going vessels. Initial capacity for truck receipt will be 30,000 bbl/d, and marine-loading rate will be 20,000 bbl per hour. NGL said service should begin in April 2017.

“We are pleased to add the Point Comfort terminal to our strategic footprint and expand our supply chain presence in the Gulf Coast,” said EVP Don Robinson.

“The terminal is backed by long-term, fee-based contracts and will enhance our ability to service additional markets for the export of crude oil and condensate via the Gulf of Mexico.”

NGL owns five Gulf Coast terminals with 850,000 bbl capacity. Most of its storage capacity resides at Cushing, where it owns 7.7 MMbbl in storage.

■ SemGroup completed its purchase of outstanding common units of Rose Rock Midstream that it didn’t already own. Prior to the acquisition, SemGroup owned 56% of Rose Rock. The company offered 0.8136 SemGroup shares per Rose Rock common unit. The offer was worth $390 million. CEO Carlin Conner said the deal simplified SemGroup’s structure so it could more easily move forward with its strategic growth plan.

■ Wolf Midstream closed on its purchase of Devon Energy’s 50% stake in Access pipeline. Deal consideration was $1.1 billion (C$1.4 billion). Buying the 214-mile crude line that transports 340,000 bo/d from the Athabasca oil sands in Alberta was Wolf’s first move since launching a year ago. Wolf is a portfolio company of Canada Pension Plan Investment Board. Under the sale agreement, Access’ toll may be reduced by as much as 30% as future thermal projects are developed.

TransCanada adjusts mainline toll offer on shipper concernTransCanada is offering a toll compromise to shippers on its mainline after

initial pushback to its discount offer. The company launched an open season last week to gauge interest in a 10-year agreement to pay 75-82 Canadian cents per gigajoule depending on committed volumes. The midstream company added an option to terminate the contract after five years with a mandatory two-year

notice period during which the tolls would increase to 83 cents to C$1.15 per gigajoule depending on committed volumes and total contract length.

Sources said last month that shippers weren’t interested in TransCanada’s 42% reduction to tolls, which are currently $1.41 per gigajoule, because of the long length of the contract. SVP Stephen Clark said that the latest offer comes after talks with shippers and that the company wouldn’t reduce the toll offer further. TransCanada’s deal requires an agreement to ship at least 1.5 petajoules.

Current contracts expire in 2020. Mainline customers include Canadian Natural Resources Ltd. and Encana, but neither has commented on the record regarding the toll offer. The line runs from Alberta and British Columbia to Ontario markets.

FERC delays Atlantic Sunrise to hear landowner commentsWilliams Partners’ $2.6 billion Atlantic Sunrise expansion of Transco pipeline

may see a delay as FERC weighs two possible route alternatives and has put a call out to affected landowners for comments by Nov. 14. The small route changes total 1.4 miles in aggregate and are on the Central Penn Line North and South segments.

Atlantic Sunrise spans 200 miles and crosses 10 Pennsylvania counties from the north-central Marcellus to a Transco interconnection in Lancaster County. The project largely comprises new 30/36/42-

in. pipe and looping. The extension has been in the works since 2014 with more than half of its route altered because of

landowner and stakeholder feedback. Anchor shipper Cabot Oil and Gas, which has committed 850 MMcf/d, expects FERC to expedite this latest issue in a timely manner. Total capacity would be 1.7 Bcf/d, and completion has been targeted for 2H17.

Analysts said the setback wasn’t yet negative. “This is adding uncertainty to the project,” Bloomberg Intelligence analyst Brandon Barnes said. “I don’t think this is material slippage yet.”

Pipelines

1.4 miles of alternative route in question for Williams project.

Analysts aren’t yet worried about schedule for 1.7 Bcf/d line.

TC offers 75-82 cents per gigajoule for 10 years with 5-year option.

SemCAMS to build 200 MMcf/d sour-gas plant in WapitiSemGroup subsidiary SemCAMS will begin construction in 2Q17 on a new sour-

gas plant in Alberta’s Wapiti area that will be able to process up to 200 MMcf/d and 20,000 bbl/d of condensate. The midstream company agreed to process 120 MMcf/d

of NuVista Energy production at the new plant for 15 years. The project is estimated to cost $227-264 million.

The Wapiti plant also will have functionality to process 350 tonnes per day of sulphur because it operates the K3 and KA plants, which are approved to process a combined 3,000 tonnes per day of sulphur. This capability offers a long-term egress option for acid gas and associated sulphur. With the new plant, SemCAMS’ processing power climbs to 330 MMcf/d of Montney gas with expansion potential. Operations are expected to begin in 2Q19, and SemCAMS is in talks with additional producers for remaining Wapiti plant capacity.

January 15, 2015 • Volume 06, No. 01

CanadianCapitalServing the marketplace with news, analysis and business opportunities

ALBERTA PROPERTIES SALE5-Non-Core PropertiesCENTRAL & WESTERN ALBERTA PPAbee, Highvale, Kakut, Majeau & MorinvilleUp to 100% OPERATED WI FOR SALE 5.7Net Production: ~400 BOED (82% Gas) MMCFEDAvg Net Operating Income: ~$189,166/MoCALL AGENT FOR MORE INFOPP 14403DV

CANADIAN JOINT VENTURE1-Prospect. 43,000-Acres. 67-Sq Miles.MAGDALEN BASIN. GULF OF ST LAWRENCE DV80-km West of SW Tip of Newfoundland.Water Depth 470 m. Drill Depth 2,500 m.>1,000 km 2D Defines FourWay Closure. MAGDALEN100% OPERATED WI; JOINT VENTURETotal Resource Potential: 5.0 BBO or --- 7.0 TCF Carboniferous Clastic Targets.CALL AGENT FOR UPDATEDV 15009

FEATURED DEALS

Eagle Energy Trust becomes a Canadian asset holder

Eagle Energy Trust unitholders have approved a special resolution to amend the investment restrictions in Eagle's trust indenture, enabling it to invest in energy assets in Canada. Eagle had been previously been limited to investing on non-Canadian assets—the company currently has production of 1,900 boepd from properties in Texas and Oklahoma. The changes won’t have any impact

on its US operations or the taxes on distributions from those operations; the company’s Canadian investments will be structured so that its Canadian operations will be taxed in the same manner as other Canadian energy companies.

Eagle wasted no time taking advantage of the change, signing a deal with Spyglass Resources Corp. to buy a 50% non-op interest in producing properties under waterflood in the Dixonville Montney C oil pool in north central Alberta, paying $100 million. The acquisition adds 1,250 boepd of low-decline production.

Producers banking on service company savingsAs producers scale back their capital spending plans in the wake of falling oil

prices, many are looking to the service sector to help them prop up their bottom lines. Crescent Point Energy is already factoring a 10% reduction in service costs into its 2015 budget and will be pushing for more if prices remain low. Others are expected

to approach their capital budgets with the same mindset.

According to a survey con-ducted by Barclays, capital spending in the US and Canada is expected to fall by as much as 30% from last year to $138.1 billion. In turn, about half of producers expect drilling and completion costs to fall 10% in 2015, including in areas such as pressure pumping, drilling fluids and directional drilling. And while producers may see the service savings as a slight respite from the decline in oil prices, the news is doubly disheartening for those service providers. Not only are they seeing declines in their own businesses, they’re being asked to take less for the services they do provide.

Service companies are already feeling the impact.

Crescent Point banking on service cost & efficiency savingsHalf of oil hedged at US$90/bbl for 2015

Although Crescent Point Energy is setting its capital budget for 2015 about 28% lower than 2014, the company expects the slimmed down budget to deliver 9% YOY production growth to 152,500 boepd. The company set its budget for the year at $1.45 million, down 28% from the $2.0 billion

forecast for 2014. The budget assumes an

initial 10% reduction in service costs. Crescent Point expects to see even greater cost reductions if low prices persist. The company is looking at ways to improve its operational efficiency and is working on a number of drilling and completion technologies that could cut costs even further.

“When prices fell dramatically in 2008 to 2009, we were able to realize a 30% reduction in our Bakken drilling and completions costs,” said CEO Scott Saxberg.

“We'll be working hard with our service providers and fully expect to see rates come down even more than they already have.”

Canadian Natural Resources cuts capex by $2.4 billionOil sands player Canadian Natural Resources is the latest producer to revisit its

capital spending plan for 2015, cutting it back by $2.4 billion to $6.2 billion. That’s down 30% from the $8.6 billion budget it laid out in November 2014 and about half

the $12 billion it expected to spend in 2014. The bulk of the reductions will come via reduced drilling and related facility capital for its North

America and International conventional operations. The company will also defer $470 million in spending at its Kirby North Phase 1 in situ oil sands project, cutting spending by 82% to $105 million from its previous forecast of $575 million. The reduced budget wasn’t a complete surprise; when it released the original budget the company warned that it was prepared to cut $2.0 billion from that if conditions warranted. CNRL said the reduced spending would allow it to continue its dividend unchanged.

CFO Corey Bieber told the Globe and Mail he did not know when spending at Kirby North might be restored.

Will defer $470 million in spending at Kirby North Phase 1 project.

Viewfield Bakken & Shaunavon plays to get nearly half of spending.

Half of producers expect drilling & completion costs to fall 10% in 2015.

Continues On Pg 6

Continues On Pg 8

Continues On Pg 13

To be taxed at rate other E&P firms pay, not at prior 34% on distributions.

Cont’s On Pg 10

NuVista expects 2016 D&C to be down 25%.

CanadianCapital

Developments & Trends

To learn more about PLS, call 713-650-1212Find more on the midstream sector at

MidstreaMNews 8 October 20, 2016

A&D

“They share our vision of the substantial growth opportunities from production in the Permian Basin,” he said. “Their financial assistance via incentive distribution relief provides us with expected accretive economics for this strategic acquisition.

Long-term, with Energy Transfer’s growing crude gathering presence in West Texas combined with our extensive mainline crude platform

and gathering assets, we expect growth opportunities for our partnerships in this very competitive region.”

To fund the purchase, Sunoco will use part of the $560 million in proceeds it netted from a public offering of 21 million common units priced at $27 per unit. Sole underwriter Barclays Capital will have a 30-day overallotment option to purchase an additional 3.15 million units, which would bring the raise to $645 million. Assuming full exercise, Sunoco Logistics would have more than 322 million units outstanding. If the deal falls through, Sunoco will use these net proceeds for general partnership purposes.

Downstream

Sunoco Logistics grows West Texas presence Continued From Pg 1

Parent Energy Transfer reduces incentive distributions by $60 million.

Sunoco Grows Permian FootprintAsset Detail§Midland Terminal

– 2 MMB total capacity (1 MMB at Vitol and 1 MMB at SunVit)– 14-lane truck station – Connected to Centurion Midland, Enterprise Midland, Permian

Express 2 (via SunVit)§North System

– 29 miles of 12” mainline plus 33 miles of gathering lines– RC Smith truck station: 4mbbls storage, 8 lanes– Dickenson truck station: 2 mbbls storage, 4 lanes§ East System

– 11 miles of 8” mainline and 10 miles of gathering lines to Midland Terminal

– Blewitt truck station: 2 mbbls storage, 4 lanes§Midkiff Mainline

– 25 miles of 12” mainline to Midland Terminal– 4-lane truck station with 52 mbbls storage§Midkiff West Lateral

– 12 miles of mainline & gathering lines into Midkiff 12” mainline– 4-lane truck station with 2 mbbls storage§ SunVit Pipeline LLC

– 38 miles of 20” mainline from SunVit Terminal to Garden City– ~ 1 MMB storage– 6-lane truck station

7

20” to Garden City

2 MMB terminal

Source: Sunoco Logistics Sept. 21 Presentation via PLS docFinder www.plsx.com/finder

Meridian Energy submits N.D. refinery plan for reviewMeridian Energy moved forward with its plans to build North Dakota’s third

refinery. The company submitted a permit application to the state Department of Health to build its Davis refinery near Belfield. The 55,000 bo/d facility will sit on 620 acres. Meridian said it plans to build a petroleum liquids delivery and uploading facility at the site, through which a Burlington Northern Santa Fe mainline runs. In its application, the company says its refinery will be only a “minor synthetic source” of air pollution as compared with most refineries, which are a “major source.”

Craig Thorstenson, an engineer with the Division of Air Quality, said the review could take a year. CEO Bill Prentice said the Davis facility could be operational by early 2018, making it the second greenfield fuels plant built in the US since 1976. North Dakota produced 1.03 MMbo/d in July, according to the latest figures available. Only 8% of Williston Basin crude is refined in the state. The rest leaves via pipeline (59%) or rail (32%).

Davis facility would refine 55,000 bo/d near Belfield, North Dakota.

Shell Midstream picks up GOM pipeline stakes

Shell Midstream Partners picked up interests in two Gulf of Mexico pipelines from its supermajor parent for $350 million. The deal included an additional 20% WI in the Mars oil pipeline and 49% WI in the Odyssey pipeline. The dropdown closed Oct. 3.

Shell Midstream’s stake in 600,000 bo/d Mars is now 71.5%. The system ships crude 163 miles from the Gulf’s prolific Mississippi Canyon to onshore storage in Louisiana at LOOP’s Clovelly facility. The line carries production from Shell’s

Mars/Olympus deepwater project. Shell Midstream is buying the entirety of its parent’s working interest in the 106-mile Odyssey, which carries 220,000 bo/d in the eastern Gulf and connects to the Delta pipeline to access onshore refineries in Louisiana and Mississippi. Genesis Energy owns the remaining interest in Odyssey.

“This acquisition further diversifies the Shell Midstream Partners portfolio with the inclusion of a well-positioned eastern Gulf of Mexico asset,” said CEO John Hollowell. “In addition, the partnership acquired an additional interest in an existing asset with a strong track record of delivery. Both Mars and Odyssey build on our key corridor pipeline strategy in the Gulf of Mexico and are advantageously positioned to continue to capture growth of offshore volumes along our footprint of assets.”

MLP paid $350 million for 20% WI in Mars, 49% WI in Odyssey.

All Standard Disclaimers & Seller Rights Apply.

January 14, 2015 • Volume 07, No. 01

InternatIonalDealsServing the marketplace with news, analysis and business opportunities

International M&A falls 21% to $60 billion in 2014

Global upstream deal activity saw an impressive 30% rise in terms of total deal value to US$185.0 billion during 2014. However, this upswing was due entirely to skyrocketing acquisition activity in the US (up 79% to $98.3 billion) and Canada (up 132% to $26.6 billion). Looking just at the international picture, activity was down 21% in terms of deal value to $60.0 billion and 30% in terms of deal count (including transactions without disclosed values) to 399.

Major increases in deal value were seen in Asia (69% to $8.0 billion), the South Pacific (442% to $11.3 billion), and the North Sea/Europe (118% to $12.7 billion). However, these increases were overwhelmed by a combined $35.0 billion decrease in activity in Africa (54% to $9.6 billion) and the FSU (72% to $9.0 billion).

Seplat’s Afren takeover bid threatened by Kurdish writedownJust days after Nigerian oil firm Seplat Petroleum Development confirmed

making a preliminary approach to acquire Afren, the target company’s takeover prospects took a hit when it released a drastically reduced resource estimate for its

Barda Rash oil development (60% WI) in the Kurdistan region of Iraq. Based on reprocessed 3D seismic and its drilling campaign, the report eliminates 190 MMbbl of previously estimated proved plus probable oil

reserves and reduces the 2C resource estimate by 80% to 250 MMbbl from 1,243 MMbbl.

The previous estimate reported in 2012 had been the basis from the London-based company’s approved development plan. It is now considering strategic options for the project in light of the update. Afren’s stock fell 30% on the London Stock Exchange to close at 27.31 pence on January 12, the day the update was released—eliminating the bump experienced when rumors of the takeover bid broke in mid-December. The news comes one week ahead of the January 19 deadline for Seplat to make a formal offer for Afren.

Chinese group offers $100 million for Kazakh oil projectContinuing 2014’s trend of non-traditional Chinese oil and gas buyers entering the

E&P space into the new year, a consortium led by publicly listed Xinjiang Zhundong Petroleum Technology Co. plans to acquire the Galaz contract area in central Kazakhstan for US$100 million in cash and debt. The oil development is operated by South Korea’s LG International (40% WI) partnered with London-listed Roxi Petroleum (34.22%) and Baverstock (23.78%), a company controlled by Roxi board member and top

shareholder Kuat Oraziman.The 44,200-acre block in

Kyzylorda province contains the Northwest Konys project plus exploration upside on the east side of the Karatau fault system. Seventeen wells have been drilled at Galaz since 2008 and Northwest Konys pilot production began in January 2012. Five wells are on extended test producing an aggregate 1,000 bopd and four more are being prepped to begin production testing.

Under the non-binding heads of terms, the Chinese consortium will acquire JV firm Galaz & Co. for $50.4 million cash plus $49.6 million in debt.

BP in talks with Rosneft to buy 20% in Siberian fieldRussian companies blocked by sanctions on other oil & gas deals

Rosneft is reportedly in talks to sell BP a direct 20% WI in subsidiary Taas-Yuriakh Neftegazodobycha, the license holder of its Srednebotuobinsk oil and gas field in Eastern Siberia. The deal would result in an effective 35.8% stake in the field for

BP, which is the Russian company’s largest private shareholder with 19.75% equity. According to unnamed sources cited by Russian daily Kommersant, the negotiations could result in

a US$700-800 million deal with closing expected in early 2015.

Rosneft acquired an initial 35.3% WI in Taas-Yuriakh for $444 million during the development phase in March 2012 and increased its stake to 100% WI in October 2013, shortly after reaching first oil. At that time the company projected 2014 production of 1.0 million tonnes (~20,000 bopd), increasing to 5.0 mtpa (~100,000 bopd) by 2017. It also assigned the field C1+C2 reserves of 134 million tonnes of liquids (~1.0 Bbbl) plus 5.47 Tcf.

THAILAND CONCESSION FOR SALE1-Onshore Concession.PHETCHABUN BASIN2-Onshore Exploration Assets. PP8-Production Licenses.Contains 12 Individual Oil Fields.20% WORKING INTEREST FOR SALE 4,000Gross Production: ~4,000 BOPD BOPD2P Net Reserves: 30 MMBOECONTACT AGENT FOR MORE INFOPP 6089

SURINAME OFFSHORE BID ROUND3-Blocks. ~6,420,000-Acres.(26,000 km2)SURINAME-GUYANA BASINHuge Prospective Blocks BWater Depths:~50-7,380 Ft. --- (15-2,250m)WORK PROGRAM BIDDING ROUND BIDProven Petroleum System ROUNDProduction: 16,000 BOPDBid Round is Closing January 30, 2015CONTACT PETROLEUM MANAGERBR 5103PP

FEATURED DEALS

Current ~20,000 bopd projected up 400% to ~100,000 bopd by 2017.

Consortium led by publicly listed oilfield service firm Xinjiang Zhundong.

New Barda Rash estimate eliminates 2P reserves, cuts 2C by 80% to 250 MMbbl.

Out of the top 30 international deals, not one buyer was a US producer.

Continues On Pg 8

Continues On Pg 11

Continues On Pg 15

Continues On Pg 6

Get more intel on this and other midstream deals.

InternationalDeals

Shell Midstream now owns 71.5% stake in 600,000 bo/d Mars pipeline.

Odyssey pipeline carries 220,000 bo/d in eastern Gulf of Mexico.

A&D

Access PLS’ archive for previous midstream newsFor general inquiries, email info@plsx.com

Volume 09, No. 14 9 iNfrastructure

Sanchez buys into Carnero Gathering & Processing JV

Building on a deal this summer, Sanchez Production Partners (SPP) will acquire the rest of parent Sanchez Energy’s interest in the Carnero Gathering and Processing JV with Targa Resources in South Texas. The latest deal involves the processing portion of the JV. SPP will pay $47.7 million cash to Sanchez for its 50% interest and assume the remaining $32.3 million in capital commitments to build the Eagle Ford project, which is expected to be operational in early 2017.

Targa is building and will operate the 200 MMcf/d Raptor cryogenic plant in La Salle County. The plant will process gas production from Sanchez’s outperforming Catarina asset, where it has devoted two-thirds of its 2016 capex. The producer is under a fixed-fee agreement for 125 MMcf/d of processing

and pipeline capacity for five years and has dedicated its Catarina acreage to the Carnero system for 15 years. The system includes 45 miles of high-pressure gathering line, in which SPP acquired Sanchez’s 50% interest in July.

“We are excited to be further aligned with Sanchez Energy and its plans for the Catarina asset and look forward to capitalizing on opportunities to grow alongside this leading Eagle Ford operator over time,” said Gerry Willinger, CEO of the general partner of SPP.

SPP also acquired an option to obtain a lease from Sanchez in Point Comfort, Texas, where a marine crude storage terminal is being built by NGL Energy Partners. The facility will house 350,000 bbl upon completion, which is expected in April 2017.

A&D

SPP pays $47.7MM for 200 MMcf/d cryo plant in Eagle Ford.

Regional Oil & Gas Intelligence November 5, 2015

Serving the local market with drilling activity, permits & deals for sale Volume 03, No. 15

DUVAL CO., TX PROPERTY3-Active Wells.SOUTH TEXAS PPProducing From Pettus & Yegua Y-21.100% OPERATED WI Available.Net Production: ~170-210 MCFD ~200Total Reserves: ~34 MBO & 22 BCF MCFDCONTACT SELLER FOR MORE INFOPP 5404RE

WANTED: EAGLE FORD PROJECTSNonOperated WI Investor. SOUTH TEXASInternational Petroleum Firm Wants To-- W--Participate as NonOperated WI Partner.Seeking Experienced Operators In Play.Budget of ~$10-$40 Million. NONOPOil or Liquids-Rich. W 5023DV

Deals For Sale

No Commission. Call 713-650-1212

All Standard Disclaimers & Rights Apply.

SOUTH TEXAS SCOUT

Sanchez’s Catarina Overview

Total Net Acres ~106,000 Average Working Interest 100% Average Net Revenue Interest 75% Planned Well Spacing (Acres) 75 – 100 Net Identified Drilling Locations 1,250 - 1,650 Gross Wells On Production 238 Awaiting / Undergoing Completions 27

EURs (MBoe) 600 – 700 D&C Costs ($MM) $4.5 F&D Cost ($ / Boe) $8.57 – $10.00 IRR @ $60 / Bbl & $3.75 / Mcf 35%+

LEF Well Economics

Acreage, Inventory & Operational Update

• Early results support stacked pay development in three

Western Catarina (~43,000 net acres)

Central Catarina (~26,000 net acres)

Eastern Catarina (~37,000 net acres)

Eagle Ford benches; Upper, Middle, & Lower Eagle Ford • Well performance currently exceeding high end

Catarina type curve through first year of development • Par�ally developed; Excellent offset operator results

• Early results in South-Central Catarina in line with the strongest to date in the asset: 30-Day IP Rates of nearly 1,350 BOE/D

• Expected further future development in South-Centralregion in 2016

• Explora�on area; full 3D seismic coverage; inversion processing in progress

• Early results ~50% above exis�ng wells in Eastern Catarina • Substan�al number of poten�al Lower Eagle Ford

drilling loca�ons

Western Catarina

Central Catarina

Eastern Catarina

Source: Sanchez Energy October 05, 2015 via PLS docFinder (www.plsx.com/finder)

Regional Activity (State Data)(10/13/15 to 11/02/15)

Compls PermitsSouth Texas (RRC 1) 60 73

South Texas (RRC 2) 39 83

South Texas (RRC 3) 2 13

South Texas (RRC 4) 8 37

Most Active Operators by Permits

➊ Marathon Oil 20

➋ Pioneer Natural Resources 15

➌ EP Energy E&P 13

Permits by Formation (by Last Scout)

Formation 11/05 10/15 09/24

Eagle Ford 143 205 151Wilcox 8 2 5Austin Chalk 6 14 8Buda 4 5 11Frio 3 1 –Vicksburg 3 2 –Barnsdall Sand 2 3 2Olmos 1 1 341-A & 98-A Cons 1 3 –Other Formations 35 52 59TOTAL 206 288 239Sources: TXRRC

Active Rigs Running (Baker Hughes) 96

SM’s Eagle Ford downspacing tests show promiseEagle Ford wells performed above type

curve for SM Energy in Q3, raising the company’s production in the shale 3% sequentially and 31% YOY to 134,500 boe/d—more than 75% of SM’s total production for the quarter across all plays and despite a decline in non-op Eagle Ford production. SM also reported successes in proving up additional drilling inventory with downspacing tests.

The company drilled multi-well pilot tests to determine downspacing potential and to add the Upper Eagle Ford to its

drilling inventory. Wells have been drilled in five of the nine planned pilot tests, with the remainder slated for 2016.

The initial test consisted of 14 wells on the gas-weighted eastern portion of SM’s acreage, downspaced to 450 ft

instead of its standard 625-ft spacing. Test 1 now has 130 days of sales and during Q3 reached a peak gas rate of 105 MMcf/d or 7.5 MMcf/d per well.

Sanchez’s Catarina development continues to outperformFor the third consecutive quarter,

Sanchez Energy’s Catarina project has been the driving force behind its Eagle Ford production. Strong well rates and accelerated development resulting from faster drilling times contributed to lower costs. The company’s results from the south central Catarina showed 30-day IP rates of ~1,350 boe/d.

Sanchez ran three operated rigs at Catarina during Q3 to bring 27

wells online. The 106,000-net-acre development area on the border of Dimmit and Webb counties, Texas, has been the focus of Sanchez’s operations

since it was acquired from Shell for $639 million in 2Q14. At the end of Q3, the company had 264 producing Catarina wells and 18 awaiting completion.

Efficiencies continued to help shave down well costs.

Q3 Eagle Ford production of 134,500 boe/d accounts for 75% of SM’s total.

Continues On Pg 3

Continues On Pg 5

Sanchez Energy releases latest Catarina results.

South Texas Scout September 23

Duke completes $4.9B buy of Piedmont Natural Gas Duke Energy’s $4.9 billion acquisition of utility Piedmont Natural Gas,

which was announced a year ago, closed Oct. 3 after receiving North Carolina Utilities Commission approval. Piedmont will keep its name and operate as a

business unit of Duke. The utility companies are major players in the proposed $5.1 billion

Atlantic Coast pipeline led by Dominion. In conjunction with the closing of the Piedmont buy, Duke sold 3% of its stake in the project to Dominion so that Dominion could retain its controlling interest. Duke owned 40% and Piedmont 10%. Dominion now owns 48% and Duke 47%. The remaining owner is utility Southern Company (5%), which recently bought out AGL Resources.

Atlantic Coast, which has been in the works for a couple of years, received a clearer timeline in August. FERC expects to issue a final environmental impact statement by June 30, 2017. It will be 564-mile system with 42/36-in. pipeline carrying 1.5 Bcf/d from Harrison County, West Virginia, to Robeson County, North Carolina. Upon completion, it will be the first major gas pipeline to service eastern North Carolina.

TEML picks up Enbridge line for $819 millionTundra Energy Marketing Ltd. (TEML) will acquire the South East Saskatchewan

(SES) pipeline system from an affiliate of Enbridge Income Fund Holdings (ENF) for $819.1 million cash. The deal adds 175,000 bbl/d of crude throughput to TEML’s portfolio, pushing its crude volumes to more than 250,000 bbl/d from Saskatchewan, Manitoba and North Dakota.

The SES system encompasses 994 miles of crude and liquids gathering line, 340 miles of trunkline and four truck terminals. The system connects to Enbridge’s mainline at Cromer, Manitoba, where it links to the main terminal of TEML’s Manitoba gathering system and to Enbridge’s Bakken expansion pipeline. TEML also operates more than 600,000 bbl storage and a truck-loading terminal at Cromer.

TEML has operated in the Williston Basin for more than 35 years. “We know and understand this part of the world, the Saskatchewan portion of which is one of the most economic oil production areas in North America,” president Bryan Lankester said.

“The acquisition of this well-cared-for asset is very complementary to TEML’s existing portfolio of midstream infrastructure.”

The deal is slated to close later this year, and all of Enbridge’s employees who

work on the system are expected to join TEML. Tundra is a subsidiary of Winnipeg-based agricultural and food industry company James Richardson & Sons Ltd.

President Perry Schuldhaus said the deal allowed ENF to monetize non-core assets at an attractive valuation. The company plans to reinject proceeds into its growth project portfolion, which stands at $9 billion and includes the Wood Buffalo extension and the Athabasca twin and Norlite projects that are expected to be in service in 2017.

The Wood Buffalo project is a new 65-mile, 36-in. heavy-crude pipeline from the Cheecham terminal to the Kirby Lake terminal near Fort McMurray, Alberta. It will ship 635,000 bbl/d with expansion up to 800,000 bbl/d. Norlite is a 277-mile, 24-in. diluent line from Stonefall terminal in Strathcona County to Fort McMurray. Capacity will be 130,000 bbl/d initially but can be expanded to 400,000 bbl/d. The 214-mile Athabasca project will twin the existing line with construction of a new 36-in. crude line from Kirby Lake to Battle River near Hardisty, Alberta. Capacity will be 800,000 bbl/d.

Line moves 175,000 bbl/d to mainline at Cromer, Manitoba.

Tundra will handle more than 250,000 bbl/d after deal.

Duke sells 3% stake in Atlantic Coast to project leader Dominion.

All Standard Disclaimers & Seller Rights Apply.

January 7, 2015 • Volume 24, No. 01

CanadianaCquirerServing the marketplace with news, analysis and business opportunities

EAST ALBERTA PROPERTY10-Wells. 2,048-Gross/Net Acres.WAINWRIGHT FIELD. T45.EDGERTON VILLAGE PPHeavy Oil Prospect With ----- Shallow Gas Production. ~35100% OPERATED WI AVAILABLE BOEDMonthly Cash Flow: ~$17,000/MonthCONTACT SELLER FOR MORE INFOPP 11478

SASKATCHEWAN PROPERTIES9-Oil Producers; 1-SWD; >10-PUDMANOR AREA. IMMEDIATE UPSIDE PPManor Tilston Oil Pool.Frobisher & Midale Oil Wells.100% OPERATED WI FOR SALE ~502Expected Future Production: 600 BOPD BOPDManor Proved Reserves: 445 MBOEManor Net Proved PV10: $23,443,000CONTACT AGENT FOR STATUSPP 13109DV

FEATURED DEALS

Canadian upstream M&A activity quadruples in 2014

Repsol’s $15.2 billion Talisman buy caps a busy 2014 in the Canadian oilpatch with $46.0 billion in upstream deals—roughly quadrupling 2013’s $11.8 billion. Of the previous six years, only 2012 had a higher tally at $54.7 billion and that included CNOOC’s $18.1 billion acquisition of Nexen. By deal count, activity declined 15% YOY to 269 transactions in 2014 from 319 in

2013 although deals with disclosed values actually rose slightly to 213 from 191.

This Canadian M&A analysis includes Repsol/Talisman because Talisman is a flagship Calgary company with a large domestic asset base, despite the fact that it operates globally and produces more oil and gas from the US and Indonesia than it does at home. However, even excluding this transaction Canada racked up $30.9 billion in 2014 deals, up more than 160% YOY.

Veresen & KKR nab Montney midstream for $600 millionEncana and Mitsubishi are selling Montney midstream assets in the Dawson area

of northeast British Columbia for $600 million to a new 50:50 partnership formed by Veresen Inc. and private equity giant KKR. Encana will receive $412 million for interests owned both directly and through its 60% stake in Cutbank Ridge Partnership (CRP),

its JV with Mitsubishi.Veresen Inc.-KKR

venture Veresen Midstream LP will acquire 500 km of gas gathering pipelines and 675 MMcfd of compression capacity. The deal also includes the Saturn compression station currently under construction, which will add 200 MMcfd of compression capacity when completed. The infrastructure gathers gas production from Encana and CRP and delivers it to various processing plants including the nearby Hythe/Steeprock facilities, which Veresen Inc. is contributing to Veresen Midstream.

Encana will continue to operate the assets on a contract basis, while Veresen Midstream will provide gathering and compression services to Encana and CRP under a 30-year fee-for-service arrangement in a 240,000-acre AMI.

Woodside enters shale patch with Kitimat buy from ApacheExecuting on a promise made to investors back in July, Apache agreed to sell

its interests in the Kitimat gas venture in British Columbia and Wheatstone project off Australia to Woodside Petroleum for $4.34 billion (US$3.75 billion). While the Australian project is a natural fit for Woodside’s offshore and LNG operational expertise, Kitimat is uncharted territory—its first

venture into onshore shale gas.Woodside is getting 50%

WI in the proposed ~1.3 Bcfd Kitimat LNG plant (10 million tonnes per annum), 460-km Pacific Trail Pipeline and 322,000 net acres (644,000 gross) of shale gas assets in British Columbia’s Liard and Horn River Basins. The acreage will provide an estimated 15 Tcf of net 2C resources. The entire project is owned in a JV with Chevron, which will operate the pipeline and LNG plant while Woodside takes over the shale acreage from Apache.

Talisman to be acquired by Spain’s Repsol for $15 billionMarking the first multi-billion-dollar foreign acquisition of a Canadian oil and gas

company since 2012, Spain’s Repsol agreed to buy Talisman Energy for $15.2 billion (US$13.0 billion). The price consists of $9.33/share in cash plus Talisman’s $5.4 billion

debt. The companies were able to strike the deal after months of on-again, off-again negotiations largely because falling oil prices cut the value of Talisman’s stock in half in less than five months. Nonetheless this is the largest deal seen

in Canada since China’s CNOOC paid $18.1 billion for Nexen in 2012.

That year saw two other Canadian producers bought up by foreign firms: Progress Energy Resources by Malaysia’s state-owned Petronas for $6.0 billion and Celtic Exploration by ExxonMobil for $3.1 billion. Following the CNOOC deal, Ottawa enacted new limits on oil sands ownership by overseas state-owned companies. These rules have had a chilling effect on foreign investment over the past two years but do not affect Talisman, whose assets in Canada target conventional oil and gas or shale rather than oil sands.

Biggest deal in Canada since CNOOC bought Nexen for $18 billion in 2012.

Continues On Pg 12

Acquires 320,000 net acres with 15 Tcf of 2C gas in Horn River & Liard Basins.

Encana takes in $412 million from sale with Mitsubishi getting the rest.

Driven by dividend-plus-growth firms, return of foreign buyers & royalty appetite.

US$3.75 billion deal also includes Wheatstone in Australia.

InternationalDeals Dec. 18

Continues On Pg 4

Cont'd On Pg 11

Continues On Pg 6

Get the latest infrastructure-related A&D from PLS.

CanadianAcquirer

To learn more about PLS, call 713-650-1212Find more on the midstream sector at

MidstreaMNews 10 October 20, 2016

■ ConocoPhillips-operated Australia Pacific LNG (APLNG) started up production from Train 2 of its project on Curtis Island near Gladstone, Queensland. The two-train project will produce 9 mtpa combined. APLNG’s second train is the island’s sixth online. APLNG combines with a BP-led project and a Santos-led project to take Curtis Island LNG production to 25.3 mtpa. ConocoPhillips owns 37.5% of APLNG along with Origin Energy (37.5%) and Sinopec (25%).

■ Petronas reaffirmed that it will study the conditions handed down by the Canadian Environmental Assessment Agency on its Pacific NorthWest LNG project before making a final investment decision. The Malaysian company’s statement quashed media reports that it was weighing a sale of its 62% interest in the project that, all told, would represent a $36 billion investment. Petronas gave a conditional FID to Pacific NorthWest early last summer, but LNG prices are down 70% in two years.

Gazprom’s Sakhalin-2 LNG eyes third production trainRussia’s only LNG plant may add a third train, taking its output to 15 mtpa.

Sakhalin-2 would expand in 2021, Gazprom said, and may source the gas from a new field at the Sakhalin Island project in eastern Russia. Current output is 10 mtpa.

Gazprom operates Sakhalin-2 (50%) and is partnered with Shell (27.5%), Mitsui (12.5%) and Mitsubishi (10%). The partners are weighing where to source the gas for the third train. Options are buying feedstock from ExxonMobil’s

Sakhalin-1 project or drilling a new gas field itself. However, Exxon may be developing its own LNG project. The plant is fed by Piltun-Astokhskoye and Lunskoye gas fields. Gazprom board member Vsevolod Cherepanov said the company plans to drill its first well at the potential Yuzhno-Kirinskoye field in 2017. Testing would follow in 2021.

Cheniere makes $5.1B offer for Cheniere Energy Partners Carrying out a promise by new CEO Jack Fusco to streamline operations, Cheniere

Energy offered to acquire the 20% stake in Cheniere Energy Partners LP Holdings it doesn’t already own. The all-stock deal values the latter company, which owns and

operates the LNG assets, at $5.07 billion.

“We believe the proposed transaction is attractive to investors in Cheniere Partners Holdings who, as new LNG shareholders, would have the opportunity to participate in the future success of the entire Cheniere complex,” Fusco said. “In addition, shareholders of Cheniere Partners Holdings would receive an attractive premium over its recent trading levels and a significant increase in

the trading liquidity of their investment.”Cheniere offered 0.5049 shares for each

outstanding publicly held share of Cheniere Energy Partners Holdings, representing a value of $21.90 per common share of Cheniere Energy Partners Holdings—a 3% premium over the Sept. 29 closing price. If approved by the boards, the deal would close by 1Q17. Cheniere Energy then would own 56% in Cheniere Energy Partners, which operates the Sabine Pass liquefaction facility on the Texas/Louisiana border. That stake is currently held by Cheniere Energy Partners Holdings.

The offer comes as Sabine Pass has been approved by FERC to double exports. The additional LNG would come from Train 2, which was recently completed and expected online in August 2017. With two trains exporting, Sabine Pass would produce 9 mtpa. Cheniere will develop up to six trains capable of producing a total 27 mtpa.

US Midstream Market Movers—Last 30 Days Source: Bloomberg

Company Ticker $/Share 10/19/16

$/Share 9/21/16

% Change

% Change

YOY

Top

5

Plains All American PAA $32.72 $27.84 18% 1%Antero Midstream AM $29.66 $25.52 16% 20%Noble Midstream NBLX $29.85 $26.40 13% -Cone Midstream CNNX $19.91 $18.03 10% 94%Columbia Pipeline CPPL $16.30 $14.78 10% 16%

Bott

om 5

Kinder Morgan KMI $20.71 $21.90 -5% -35%Shell Midstream SHLX $28.67 $30.05 -5% -21%Sunoco Logistics SXL $27.40 $28.19 -3% -8%Energy Transfer ETP $36.61 $37.28 -2% -21%Holly Energy HEP $33.37 $33.84 -1% -1%

Note: Includes public, US-based companies operating in the midstream space, limited to >$1.00/share and market cap >$500 million.

Cheniere’s offer represents 3% premium to Sept. 29 closing price.

FERC greenlights export of Train 2’s 4.5 mtpa capacity.

LNG

Information & Research

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All Standard Disclaimers & Seller Rights Apply.

January 6, 2015 • Volume 08, No. 01

QuickPriceServing the marketplace with news, analysis and business opportunities

TUSCALOOSA DRILLING PROJECT

~20,000-Contiguous Gross Acres.

MAJORITY IN PIKE CO., MISSISSIPPI

TUSCALOOSA MARINE SHALE DV

Also Tangipahoa & St. Helena Ph., LA

169-Drilling Locations. 80-Acre Spacing.

Offsets Goodrich, EnCana --

-- Sanchez and Halcon

SEEKING JV PARTNERSHIP; 75% NRI TMS

Area EURs: 600-800 MBO/Well PLAY

Area Also Contains High BTU Gas.

Leases Expiring in 2018-2019

DV 3395L

ARANSAS CO., TEXAS PROPERTY

11-Active Wells. ~3,200 Acres.

NINE MILE POINT (CONS. FIELD)

Frio Consolidated PP

Liquids Rich Natural Gas

85% OPERATED WI; 83% Lease NRI

Gross Production: 41 BOPD & 1.3 MMCFD

Net Production: 28 BOPD & 936 MCFD

6-Mn Avg Net Cash Flow: $161,186/Mn

PDP PV10: $ 2,216,000

Total Proved PV10: $8,652,000 193

All Acreage is Held By Production BOED

BIDS DUE BY JANUARY 15, 2015

PP 2675DV

FEATURED DEALS

Natural gas prices drop

below $3.00 at year's end

Natural gas prices closed at a two-plus

year low of $2.89 at year’s end, down

heavily from the ~$3.80-$4.00/MMBtu

script that dominated most of the back

half of 2014, with Henry

Hub falling 29% from

November’s close of

$4.09 on the month. Prices were still

within or just modestly below the 2H14

trading range in the first half of the

month, still coming off a late November

cold snap which drove prices as high

as $4.49. However temperatures once

again began coming in warmer than

norms throughout December, pressuring

prices and ultimately leading to an

~$0.80/MMBtu (22%) collapse during the

final two weeks of the year.

WTI at 5¾ year lows as slide continues into 2015

Most of us in the oil space are happy to say goodbye to December, which saw the

front month WTI crude futures contract shave off another $13/bbl on the month (or

19%) to close New Year’s Eve at $53.27. The markets did manage to stabilize during

the middle of the month with a valiant ~two week attempt to consolidate around

$55/bbl. That's the most stability we’ve

seen since November

when WTI vacillated

around $75 for about

three weeks—ultimately broken by

OPEC. However, prices ultimately

failed to hold, breaking $55 between

the holidays and closing the year on a

low note. The bearish momentum has

continued into 2015, where WTI has

now burned through the lower $50s and

sat at $47.93 as of Tuesday’s close. This

amounts to a 27% decline over the past

month, and represents the lowest price

level since March 2009. Last year also

amounted to the second largest price

drop for WTI ever on a percentage basis

with a 46% YOY decline (still trumped

by 2008). There hasn’t been much

specifically bearish news driving the decline over the past several days, aside of

course from increasing crude and refined product stocks, but the market should have

already known this was coming. In fact, a few bullish items have hit the wires, but

have failed to have any noteworthy impact.

Brent has generally followed the same path as WTI, also falling $13 (18%) to a $57.33/

bbl close in December, and is now down to $51.10 as of Tuesday.

Crude oil & natural gas settlement prices

Most Recent 01/06/15

6 Mths Ago 07/03/14

1 Yr Ago 01/03/14

2 Yrs Ago 01/04/13

Oil

WTI Front Month$47.93 $104.06 $93.96 $93.09

WTI 12-Mth Strip$53.80 $100.27 $92.08 $93.98

Brent Front Month$51.10 $111.00 $106.89 $111.31

Brent 12 Mth Strip$58.47 $109.24 $104.86 $107.28

Gas

Henry Hub Front Month $2.94 $4.41 $4.30 $3.29

Henry Hub 12 Mth Strip $3.01 $4.32 $4.25 $3.55

Financial

S&P 5002,003 1,978 1,831 1,466

Source: OTC Global Holdings Market Data

OILGAS

1. WTI breaks $50.00 after

dropping 50% in 2014.

2. Markets keep breaking floors –

first at $75.00, then at $55.00.

3. Cushing getting hit hard;

stocks are up 29% over past

month to 9-month high.

4. Libya down again, but Russia

& Iraq producing at multi-

decade highs.

5. Henry Hub fell 29% in

December, with the majority of

that during final 2 weeks.

6. Record production combining

with mild winter in one-two

natural gas punch.

7. Tudor says less oil drilling will

drop natural gas by 1.0 bcf/d.

QuickLook

WTI fell $13/bbl (19%) in December,

46% for all of 2014.Henry Hub fell about $0.80, or 22%,

during last two weeks of 2014.

Continues On Pg 3

Continues On Pg 2

All Standard Disclaimers & Seller Rights Apply.

January 2, 2015 • Volume 04, No. 16

OilfieldServiceSServing the marketplace with news, analysis and business opportunities

TUSCALOOSA DRILLING PROJECT~20,000-Contiguous Gross Acres.MAJORITY IN PIKE CO., MISSISSIPPI TUSCALOOSA MARINE SHALEAlso Tangipahoa & St. Helena Ph., LA DV169-Drilling Locations. 80-Acre Spacing.SEEKING JV PARTNERSHIP; 75% NRI TMS2-D Seismic Available PLAYArea EURs: 600-800 MBO/WellLeases Expiring in 2018-2019DV 3395L

ALASKA ROYALTY ACREAGE 15,930-Gross/Net Acres.UPPER COOK INLET BASINKITCHEN LIGHTS UNIT (N. BLOCK) RRMiocene Tyonek & Oligocene HemlockDeep Sands: 11,000-16,500 Ft.Multi Pay Intervals Present~4.45% ORRI In Leases.Offset Well Tested Over 5,000 BOPD ORRI-- From Tyonek Deep Channel Sands.Estimated Project Reserves: 89 MMBO3rd Party Reserve Report Available.Continued Development by Furie.CALL SELLER FOR DETAILSRR 5100

FEATURED DEALS

Technip spies other deals after withdrawing CGG offer

Technip has formally withdrawn efforts to take out fellow French seismic leader CGG following the rebuffing of an unsolicited $1.83 billion cash bid for the company by Technip. The offshore E&C leader said that following CGG’s refusal, Technip proposed a number of alternate options to a tender offer, but said these efforts were similarly unfruitful. In a separate

statement, CGG said that none of the proposed options created value for the company, and The Financial Times reported that board members viewed the offer as opportunistic in light of lower oil prices. Regardless, CGG asserted it was in position to weather current difficult market conditions.

Canadian service firms give signs of things to comeIn an early indicator of where service capex budgets are headed in the Lower 48 as

they are announced in coming months, Canadian service firms have been announcing drastically reduced 2015 spending plans and newbuild construction halts in anticipation

of lower producer cash flows. Many of these firms also have US operations, for even better visibility on things to come. Number one Canadian driller Precision Drilling cut next year’s budget

44% to C$493 million from 2014’s C$885 million and idled its new rig construction program “until we see an improved commodity price environment and rising customer newbuild demand,” said CEO Kevin Neveu. The 2014 plan is also being cut slightly from a prior C$908 million. Precision will complete 16 currently under construction rigs, 15 headed for the US and one for Kuwait, but is planning no further deliveries next year.

Precision is trimming excess fat for leaner times as well, announcing it has sold its US coiled tubing assets for C$44 million cash to an undisclosed buyer. As of YE13, Precision’s C/T fleet consisted of eight units in the Marcellus and Bakken shales, and Peters & Co. believes the price tag represented replacement cost.

GE guides down for oilpatch efforts in pivotal 2015 General Electric is positioning to weather the downcycle with stoicism while

picking up new business, and businesses, along the way. GE is calling 2015 a “pivot” year, as it digests the massive ~$15 billion acquisition of Alstom’s power assets (closure in Q2), raises proceeds from non-industrial, non-core asset sales and cuts

costs to mitigate the impact of cheaper oil. GE anticipates industrial profits up 10% or more next year, but as for oil and gas specifically,

while the division saw $4.9 billion in orders in Q3, it is already seeing headwinds. GE cut its growth outlook from high single- to low double-digit growth down to mid-single digit expectations. CEO Jeff Immelt called crude pricing issues a short term industry challenge. The company now hopes to keep oil and gas profits and revenues fairly flat through cost controls, although acknowledging that they very well may slide as much as 5%, particularly under capex freeze scenarios. Its exposure to the space is more geared toward production and less than peers on more volatile onshore unconventionals.

Assessing the service sector damagePrognosticators parse impact of crude plunge on services

With crude now down about 50% from its summer highs and E&Ps slashing capex left and right, some sense of the impact on the service sector is starting to come to light. Fortunately, with ongoing projects unlikely to have their plugs pulled, there is still probably a month or two of “full steam ahead, ” but some time next quarter activity decreases should begin to be more heavily felt, and it is worthwhile to examine who is best and worst positioned, how large the damage is likely to be, and how long a

trough could last. As for fracking,

PacWest Consulting recently did a deep dive conference call on its expectations, and the firm anticipates an 8% demand (as measured by hp) and price cut next year in US land. The drop represents a 12% decline in the number of horizontal wells fracked, offset somewhat by the continued shift toward more sand, stage-count and HP-intensive fracs. That said, frac stages are still expected to decrease 6%.

CGG deal dead in water; company cited opportunism by Technip.

PacWest sees frac demand & pricing down 8% next year.

Oil & Gas segment sales & profits projected down 0-5% next year.

Precision cut its 2015 budget 44% to C$493 million from 2014’s C$885 million.

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All Standard Disclaimers & Seller Rights Apply.

January 7, 2015 • Volume 08, No. 01

MidstreaMNewsServing the marketplace with news, analysis and business opportunities

TUSCALOOSA DRILLING PROJECT ~20,000-Contiguous Gross Acres.MAJORITY IN PIKE CO., MISSISSIPPITUSCALOOSA MARINE SHALE DVAlso Tangipahoa & St. Helena Ph., LA169-Drilling Locations. 80-Acre Spacing. TMSSEEKING JV PARTNERSHIP; 75% NRI PLAYArea EURs: 600-800 MBO/WellArea Also Contains High BTU Gas.DV 3395L

OKLAHOMA MINERAL PACKAGE 28-Active; 5-Compl; 1-Permit; 1-WOC985-NET MINERAL ACRESMISSISSIPPIAN & WOODFORD M71 Active Permits Offsetting PositionCURRENT & ONGOING DEVELOPMENT3/16ths Royalty On Most Current Leases.Net Prod: 8 BOPD, 27 MCFD, 4 BNGLD MISSISSI-Total Monthly Revenue: ~$58,000/Mn PPIANWoodford EUR’s: ~350 MBOE/WellWoodford EUR/Unit: 772 MBO & 4.8 BCFMississippian EUR’s: ~350 MBOE/WellMiss Lime EUR/Unit: 1.4 MMBO & 5.6 BCFOffers Due: January 15, 2015M 2098RR

FEATURED DEALS

Midstream sector a pipeline for stability & growth

While oil prices plunged unabashedly throughout the second half of 2014, and continue their fall as the new year gets underway, midstream MLPs that operate under long-term fee-based contracts are a continued bright spot for investors seeking both the stability that fixed, incremental income brings and the growth that needs to occur due to booming US production.

Imperviousness to price swings as well as high demand for services kept

midstream investment flowing freely last year, particularly in IPOs. The sector is expected to be on pace to perform similarly this year, staying buoyant due to volumes that will flow under fee-based contracts, in many cases, with the MLP's sponsor firm itself.

DOT railcar regulations may need more time, study saysA railcar industry trade group says one-third of the oil transported out of the

Bakken by railcars could be forced onto trucks in the next four years. The Railway Supply Institute claims that there simply aren’t enough resources to retrofit all the

railcars that need to comply with new US Department of Transportation standards within two years, resulting in the idling of tens of thousands of cars. The DOT is expected to complete standards and compliance

deadlines for tank cars early this year after initial proposals made last July.

“They can’t all be modified by the deadline, and the only alternative would be to yank them out of service,” said Kevin Neels of the Brattle Group, which the Railway Supply Institute commissioned for the study.

About 75,000 older tank cars, known as DOT-111s, fall into the category requiring the upgrades as they have been determined to have the least crash-resistant components. It was DOT-111s that crashed and exploded in Lac Megantic, Quebec in July 2013, killing 47 people, prompting continent-wide safety concerns.

Veresen & KKR will spend billions in Montney buildout Veresen Inc. and legendary investment firm Kohlberg Kravis Roberts & Co.

formed 50:50 JV Veresen Midstream into which the partners will invest more than $4.2 billion (C$5.0 billion) to support production in the liquids-rich Montney gas play on the Alberta-British Columbia border. Veresen Midstream’s keystone investment

will be pipeline and processing assets acquired from Encana and its Cutbank

Ridge Partnership JV for about $509 million (C$600 million). Then, Veresen Midstream will provide compression and transportation services to the sellers for 30 years. For Encana, the transaction unlocks $412 million in value from non-core assets it could apply to drilling. For Veresen and KKR, the deal illustrates the edge non-drilling companies have in picking up solid assets while financing options for cash-strapped upstreamers in the era of cheap oil becoming tighter.

The assets are in the Dawson, BC area operated by Encana both independently and via its Cutbank Ridge Partnership JV with Mitsubishi Corp.

Cheniere’s Corpus Christi LNG plans coming togetherCheniere Energy received word that FERC had approved plans for its Corpus

Christi LNG liquefaction facility and related infrastructure. The project will have three 4.5 mtpa LNG trains, giving it aggregate production capacity of 13.5 mtpa. The site

will also include three LNG storage tanks with capacity of about 10.1 Bcfe and two LNG carrier docks. Cheniere believes LNG exports

from the facility could begin in 2018. Right now, the plant is awaiting US Department of Energy approval to ship to markets not covered by US free trade agreements.

In the meantime, Cheniere and Kinder Morgan Texas Pipeline, Kinder Morgan Tejas Pipeline and the Tennessee Gas Pipeline Co. have entered a multi-year storage and 15-year transport agreement to ship gas to the proposed Corpus Christi LNG plant. Under the terms of the agreement, Kinder Morgan will provide 563 MMcfd of transportation service and 3.0 Bcf of storage capacity to serve the 1.8-Bcfd facility. The deal could also be increased to include up to 820 MMcfd of capacity if warranted.

FERC approval obtained, awaiting DOE nod to ship to non-FTA markets.

Expects 1.2 Bcfd processing capacity & 800 miles of gathering pipes by 2018.

DOT says over 16,000 cars a year can be retrofitted, reality says 6,400-6,600.

At least nine IPOs queued up for midstream investors so far this year.

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All Standard Disclaimers & Seller Rights Apply.

January 13, 2015 • Volume 08, No. 02

CapitalMarketsServing the marketplace with news, analysis and business opportunities

NORTH TEXAS SALE PACKAGE 18-Wells. ~4,000-Gross Acres.PARKER, JACK & ERATH COUNTIESBig Saline, Marble Falls, Atoka Sand, PP-- & Conglomerate Reservoirs.Behind-Pipe Potential In Each WellAdditional Barnett Shale PotentialAll Acreage HBP. 18 Leases. 19275-100% Operated WI; 80% Lease NRI MCFDGross Production: 271 MCFD & 33 NGLsNet Production: 192 MCFD & 23 NGLPP 3426DV

KERN CO., CA PROPERTY ~18,000-Contiguous Net Acres.BEER NOSE FIELDBloemer Tight Sandstone Objective. PPEstimated Depth: 10,000-15,000 Ft.Also Monterey, Belridge, Gibson, Oceanic,Santos, Tumey & Kreyenhagen Potential. TIGHT100% OPERATED WI; ~77% NRI SANDGross Production: 36 BOPD & 57 MCFDNet Production:27 BOPD & 44 MCFD6-Mn Avg. Net Cash Flow: ~$28,800/MnPP 5217DV

FEATURED DEALS

Rice Midstream IPO raises $474MM in tough marketAfter a fairly banner 2014 for energy IPOs on the whole but a significant dry spell for all segments other than midstream through the last few months of the year, Rice Energy put a nice bow on 2014 with its buzzer beater Rice Midstream Partners IPO. Rice sold 28.75 million units at $16.50, for total gross proceeds of $474.4 million, and $441.6 million net. Units priced 17.5% below the midpoint of the

targeted price range of $19-$21/unit, probably reflecting the challenges the energy sector has seen of late in terms of obtaining financing. However, in an interesting turn for an underpriced IPO, subsequent demand was strong enough to merit full exercise of a 3.75 million unit option (included in the above gross proceed total) which boosted proceeds by $61.9 million.

Upstream MLPs under fire as distributions cut Upstream MLPs have been the subject of much discussion of late as a particularly at-risk segment of the energy patch, and these concerns have in fact been realized for at least some partnerships with distribution and capex cuts. MLPs in general have been favored for their bond-like, high-yield distributions, stemming from preferential tax treatment for reinvesting a high percentage of profits back into the business. However, they also generally rely heavily on debt to fuel growth. And unlike their midstream brethren which are better positioned to weather recent commodity volatility with long-term, fixed-price contracts, upstream MLPs face full exposure to the recent oil and gas price declines, except to the degree they make use of hedges. However, hedges will largely peel off over the course of the year, and many of these partnerships will soon face the difficult decision of using cash to cover interest requirements and maintaining what may have become unsustainable payouts, or slashing the distributions which drew investors to them in the first place so they can make debt levels more reflective of current economics.

Concho dials capex back $1.0 billion in second look In a rather noteworthy example of what many companies which announced 2015 spending plans early are dealing with these days, Concho Resources revised its capex for this year to more accurately reflect current market conditions. In early November when WTI was still trading above $78/bbl, Concho had announced a $3.0 billion 2015 budget targeting ~30% production growth, but warned that it would ease spending if oil prices didn’t firm up over the next few months. With oil now near $45, that clearly hasn’t happened, and Concho has proceeded accordingly with a new $2.0 billion plan which is 33% lower than prior guidance and down 23% YOY vs. 2014’s $2.6 billion. The new plan contemplates $1.8 billion in D&C spend (down 33% from the prior $2.7 billion), with ~$1.3 billion or 72% of spend targeting the Delaware Basin (down 25% vs. prior budget, up from 64% of total spend), $300 million or 17% targeting the Midland Basin (down 49% vs. prior budget and 22% of total) and the remaining $200 million or 11% targeting the New Mexico Shelf (down 47% from prior budget and 14% of total).

Southwestern plans multibillion equity raise to fund buys The implications of Southwestern Energy’s $4.98 billion acquisition of West Virginia and southwest Pennsylvania assets from Chesapeake Energy (plus another $394 million in add-ons in the region from Statoil) are beginning to become apparent for the company, with impacts on both Southwestern’s capital structure and capex. The company is finally providing a clearer picture of how it plans to permanently fund the Chesapeake deal. The acquisition was funded at closure with a $4.5 billion bridge loan and a two-year $500 million unsecured term loan, but significant sums of longer-term debt and equity were clearly needed.In line with its previously announced intentions, Southwestern announced a proposed equity sale which should raise $1.8- $2.1 billion, depending on whether options are exercised. Specifically, the company plans to sell 20.26 million shares of common with a 3.04 million share option, and 26 million depositary shares (each amounting to a 1/20th interest in Series B mandatory preferred shares) with 3.9 million shares in possible options.

Should raise $1.8-$2.1 billion in equity depending on whether options go.

Boosting focus on Delaware Basin from 64% of prior budget to 72%.

Upstream MLPs are choosing between debt loads & distributions.

Units priced 17.5% below midpoint at $16.50 but option fully exercised.Continues On Pg 4

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All Standard Disclaimers & Seller Rights Apply.

Serving the US upstream industry with information, analysis & prospects for sale Volume 26, No. 08Petro ScoutMay 21, 2015 e&Pwww.plsx.com

REEVES CO., TX PROSPECT ~4,600-Net Acres.DELAWARE BASINObjectives: Wolfcamp (A,B,C)All Depths. All Rights. L80-Acre Down Spacing Pilots Underway.

Subsurface Geology Data Available

100% OPERATED WI; 75% NRI WOLFCAMP

Wolfcamp A Approx. IP: ~1,091 BOED

Wolfcamp B/C Approx. IP: ~1,190 BOED

Wolfcamp EUR’s: 300-450 MBO/Well

PKG UPDATED WITH NEW ACREAGE

L 5187DV

COLORADO DRILLING PROJECT~43,700 Net Acres.LINCOLN & KIT CARSON COUNTIES

MISSISSIPPIAN / PENN TARGETS

Miss-Spergen & Penn-Cherokee. <7,500’. LMultipay Objectives. Shallow Depths.

Defined By Extensive 3-D Seismic-- MULTIPAY

-- Geology & Geophysics Data.100% OPERATED WI; ~80% NRI

221 Active Offset Wells, 150 Offset Permits.

L 4489DV

FEATURED DEALS

Hess’s Bakken costs falling,

targeting $6.0-6.5MM/wellHess’s lean manufacturing approach in

the Bakken is leading to higher production

and cheaper wells. Q1 volumes averaged

108,000 boe/d, up 70% YOY

and 6% sequentially. A total

of 70 wells were brought

online in the play during the quarter,

down from 96 in Q4. Well costs fell to

$6.8 million from $7.1 million in Q4 and

$7.5 million in 1Q14. Hess expects costs

to fall further, with 2015 wells averaging

$6.0-6.5 million.During Q1 Hess reduced its Bakken

rig count to 12 from 17 at the end of

2014. The company is running currently

eight rigs in the play and will continue

with that number for the remainder of

the year. D&C plans call for 178 wells

drilled, 214 completed and 213 turned to

sales compared to 261, 230 and 238 last

year, respectively.

Noble’s DJ Basin spud-to-rig release days fall to seven

In the DJ Basin, Noble Energy has driven spud to rig release times for 4,500-ft

laterals down to just seven days as of Q1, a 23% reduction YOY. Notably, the company

drilled a 9,280-ft lateral in just seven days.

“We’re now averaging seven days from spud-to-rig release for a standard lateral

length well, almost as fast as we used to drill vertical wells,” said chairman, president

and CEO David L. Stover during a conference call.

The company is drilling

wells so quickly that it

will end up drilling more wells than

anticipated in 2015 and has taken funds from the Marcellus and reallocated them to

the DJ. Currently Noble is drilling 70% of the footage of 2014 with 40% of the rigs.

The company ended Q1 running four rigs and one completion crew in the DJ. In H2,

an additional completion crew will be added as needed.

Reduced drilling times and equipment optimization has led to a 5-15% reduction

in costs vs. 2014. Noble foresees further savings via lower service costs and possible

use of slickwater, which could save $2.0 million per well.

Parsley’s rookie hz drilling season delivers peer-leading results

Parsley Energy’s well performance has continuously improved since it began

drilling horizontal wells a year and a half ago. The company has drilled 30 Wolfcamp A

or B wells thus far and, based on the 30-day data, recently introduced a type curve with

estimated recoveries of 1 MMboe. In the Wolfcamp B during Q1, the 30-day

peak IP per 1,000 ft of lateral

improved 30% YOY to 231

boe/d. According to COO Matt Gallagher,

the improved performance is owed to higher stage density, more slickwater stages,

increased proppant per stage and optimal placement of the lateral within the zone.

Parsley’s improved wells are outperforming many of its peers in the Midland Basin.

In Upton County, the company’s Wolfcamp B 24-hr IPs are 75% higher than the average

when adjusted for lateral length. The Ratliff-28-1 H Wolfcamp B well is credited with

flowing the highest reported oil rate of all horizontals in Upton, according to IHS. In

Reagan County, data suggests Parlsey’s 24-hr IPs for Wolfcamp B wells are 55% higher

than the county average when adjusted for lateral length.

Devon surges past guidance on Eagle Ford performance

Completion mods push positive results across multiple plays

Fueled by the Eagle Ford, Devon’s oil production exceeded guidance by 12,000

bo/d during Q1 at 272,000 bo/d. Based on the results, the company has increased its

oil growth target from 20-25% to 25-30% (270,000 bo/d) for the full year. Q1 overall

volumes also overshot guidance, averaging 685,000 boe/d (60% liquids),

up 3% vs. Q4 and 22% YOY. Devon expects volumes to grow 5-10%

this year to an average of 667,000 boe/d. Capex was reduced by $250 million to $3.9-

4.1 billion on an improved LOE outlook

and accretive midstream transactions.

Since it took control of the Eagle Ford

position it acquired from GeoSouthern in March 2014, Devon has grown production in

the play 140% to 122,000 boe/d (62% oil). In the last quarter alone volumes jumped 24,000

boe/d, exceeding expectations and creating a bottleneck that will prevent growth in Q2.

Devon’s Eagle Ford drilling is concentrated in the Lower Eagle Ford where the

company added 79 new wells to production in Q1.

Eagle Ford output has risen 140% since

it took over the assets in March 2014.

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Bakken well costs stood at $7.1MM

at YE14, already down to $6.5MM in '15.

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Noble nearly drilling horizontals in the

time it used to take it to drill a vertical.

Wolfcamp B rates are 75% higher

than peers in Upton County.

All Standard Disclaimers & Seller Rights Apply.

December 31, 2014 • Volume 25, No. 18

TransactionsServing the marketplace with news, analysis and business opportunities

EAST TEXAS SALE PACKAGE 12-Active Wells. 3-SWD. ~3,700 Acres.BUNA WEST & SILSBEE FIELDSHARDIN & JASPER COUNTIES PPWilcox Sands 10,000 Ft.-15,000 Ft.Additional Drilling Locations Identified58-100% Operated WI; ~73 Lease NRI 191Gross Production: 77 BOPD & 888 MCFD BOEDNet Production: 44 BOPD & 530 MCFDJune 2014 Cash Flow: ~$156,600/MnPDP PV10: $4,826,000BIDS DUE BY JANUARY 15, 2015PP 2351DV

KERN CO., CA PROPERTY ~18,000-Contiguous Net Acres.BEER NOSE FIELDBloemer Tight Sandstone Objective. PPEstimated Depth: 10,000-15,000 Ft.Also Monterey, Belridge, Gibson, Oceanic,Santos, Tumey & Kreyenhagen Potential.100% OPERATED WI; ~77% NRI TIGHTGross Production: 36 BOPD & 57 MCFD SANDNet Production:27 BOPD & 44 MCFD6-Mn Avg. Net Cash Flow: ~$28,800/MnPP 5217DV

FEATURED DEALS

Whiting seals buyout of Bakken peer Kodiak

There is one less publicly listed Bakken producer following the closing of Whiting Petroleum’s acquisition of rival Kodiak Oil & Gas. The deal created a combined company with a market cap north of $6.0 billion based on the stock price the day before closing. Whiting now has the highest Bakken/Three Forks

production at a pro forma 125,000 boepd for Q3, squeaking by long-time leader Continental Resource's 121,600 boepd.

The deal also increased Whiting’s Bakken/Three Forks inventory by 158% to 3,460 net drilling locations across 855,000 net acres. YE14 proved reserves for the combined company total 780 MMboe (83% crude, 7% NGLs), up 29% compared to Whiting and Kodiak’s YE13 sum.

Southwestern buys more Marcellus/Utica for $394 millionAlso closes $5.4 billion initial acquisition from Chesapeake

Statoil is selling a 5.8% stake in its Marcellus and Utica JV assets in northern West Virginia and southern Pennsylvania to new partner Southwestern Energy for $394 million and retaining ~23% WI. Having also closed its $5.4 billion purchase of Chesapeake’s 67.5% WI, Southwestern’s newly acquired interests will rise to 73.3% WI, representing 443,000 net acres.

The Statoil deal adds incremental October

net production of 29 MMcfed and 30,000 net acres targeting the Marcellus, Utica and Upper Devonian for Southwestern. Statoil had a preferential right to buy Chesapeake’s stake when that company’s deal with Southwestern was announced in October, but chose not to exercise it. Including these properties and others in the play, Statoil retains a strong Marcellus position covering ~570,000 net acres with pro forma Q3 net production of 759 MMcfed.

The Statoil deal is expected to close in 1Q15 and will be financed fromSouthwestern’s revolver.

Oxy in talks to buy private Permian driller Three RiversCash-rich after receiving $6.0 billion in the spin-off of its California business,

Occidental Petroleum is looking to supercharge its core Permian growth engine by pursuing privately held Three Rivers Operating Co. II LLC. Industry sources contacted by PLS have estimated values in the $1.20-1.35 billion for the deal. A Bloomberg story citing an unnamed source said the companies are discussing a price below $20,000/acre—implying a value below $1.75 billion based on Three Rivers’ 82,000 net acres at YE13 plus 5,400 net

acres picked up this summer.Austin, Texas-based Three

Rivers II launched in August 2012 with the acquisition of 15,000 net acres and 1,900 boepd in the Midland Basin from Meritage Energy. Backed by Riverstone Holdings, the company at YE13 touted 25,000 net acres in the Midland Basin, 22,000 in the southern Delaware Basin and 5,000 in the Central Basin Platform representing a drilling inventory exceeding 1,800 locations (average 90% WI) targeting the Wolfcamp, Cline and Wolfberry combo play.

Repsol strikes, snapping up Talisman for $13 billionCapitalizing on falling oil prices to gain a substantial upstream foothold in North

America, Repsol has struck a deal to acquire Talisman Energy for $13 billion. The purchase price consists of $8.00/share (C$9.33/share) in cash plus the Calgary company’s $4.7 billion debt. Unanimously approved by both companies’ boards, the deal will boost Repsol’s pro forma 2014 production by 76% to over 4.08 Bcfed immediately and significantlyexpanditsexplorationportfolio.Thecombinedcompanywillhaveapresence

in more than 50 countries with 27,000 employees.

Cash-rich Repsol had been gearing up for a strategic upstream acquisition, building up a $12 billion-plus war chest this spring through the divestment of its equity in Argentine explorer YPF, a $5.0 billion settlement with Argentina over the 2012 seizure of a 51% stake in YPF, and the sale to Shell of its Latin America-focused LNG business. At the time, Repsol said it was shopping for companies or assets within the OECD with development potential, scale, extra growth capacity and above 8% return on capital.

Bids $8.00/share after Talisman tagged a low of $3.46/share.

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Gets additional 30,000 net acres & 29 MMcfed from Statoil interest.

Creates largest producer in Bakken with Q3 output of 125,000 boepd.

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PLS sources value deal for Riverstone-backed company at $1.20-1.35 billion.

Access PLS’ archive for previous midstream newsFor general inquiries, email info@plsx.com

Volume 09, No. 14 11 iNfrastructure

ChevronPhillips' petrochem project to start up in 2H17

Chevron Phillips’ $6 billion Gulf Coast petrochem expansion is in the home stretch, with completion expected by 2H17, the company has said.

Announced six years ago, the project includes an ethane cracker at its Cedar Bayou

complex in Baytown, Texas, that will be able to produce 1.5 million metric tons per year. The cracker will feed two polyethylene plastics facilities in Old Ocean that will manufacture 500,000 tons each. One will produce bimodal high-density PE (HDPE), and the other will make metallocene linear low-density PE (LLDPE).

Chevron Phillips will be among the first of a spate of petrochem projects cropping up along the Gulf. The coast’s potential changed when West Texas NGLs started being produced in large volumes. ExxonMobil is building a 1.5-million-ton cracker in Mont Belvieu and recently announced it may develop a world-scale project with SABIC. Total is weighing a $2 billion cracker with 2.2 million lb capacity in Port Arthur. Just across the border in Westlake, Louisiana, South Africa’s Sasol wants to build an $8.1 billion cracker and petrochem complex with 1.5 million metric ton capacity. That project is slated for start-up in 2H18. Also in the Lake Charles area, Axiall and Lotte aim to build an ethane cracker and monoethylene glycol plant for $3 billion. In 2019, the complex is expected to export 1 million metric tons of ethylene per year.

Downstream

The buy also offers optionality for emerging Pennsylvania Utica development.The acquisition’s benefits will be felt this year as well. Annual throughput will be

up 45% from 2015. RMP will also see 120% EBITDA growth from 2015 to $135-145 million. Distributable cash flow will be up 110% this year to $115-125 million. RMP

expects to exit 2016 with 20% distribution growth as well and for that growth target to extend through 2023 because Rice’s new acreage adds

462 drilling locations. RMP’s 2016 capex won’t change, however. For 2017, growth capex will be $300-360 million, up from a previously expected $150-180 million.

“This deal represents the largest core dry-gas Marcellus acquisition to date, one that is truly transformational for Rice Energy, Rice Midstream Partners and our respective shareholders,” CEO Daniel Rice said. “This acquisition adheres to our proven strategy of pursuing core shale gas acreage, leveraging our industry-leading technical shale team to deliver best-in-class well results and capturing a greater share of the value chain through our premier midstream services business.”

RMP will fund the purchase with borrowings under its revolving credit facility and either equity and debt financings before closing or the issuance to its parent of up to $250 million common units. The company’s revolver has been increased to $850 million from $450 million. Closing is expected in 4Q16.

LNG

Rice Expects 45% Increase to 2017 Throughput

1. New acreage dedication will fall under the existing RICE & RMP Gas Gathering Agreement with the same fee structure.2. Excludes PA Utica.3. Excludes ~5,000 net royalty acres, the majority of which are leased to RICE.

2017E Throughput 900-950 MDth/d 370-390 MDth/d 1,270-1,340 MDth/d

2017E Water Volumes 900-1,000MM gallons 175-225MM gallons 1,075-1,225MM gallons

2017E EBITDA(1) $135-145MM $40-50MM $175-195MM

2017E Growth Capex $150-180MM $150-180MM $300-360MM

Appalachia AcreageDedication(2) 119,000 acres 80,000 acres(3) 199,000 acres

2017E DCF/LP unit Accretion

N/A N/A 5-10%

Source: Rice Energy Sept. 26 Presentation via PLS docFinder www.plsx.com/finder

Rice Midstream boosts throughput 45% Continued From Pg 1

2017 growth capex expected to be $300-360MM in Marcellus.

Among first of Gulf Coast petrochem projects worth billions.

Total to lead Ivory Coast LNG import projectCote d'Ivoire may begin receiving LNG in mid-2018 through an import facility built

by a Tota. The country signed a pact for the project, which would stimulate energy production. Demand for electricity is growing 10% each year, according to the Ivory Coast

energy ministry, but a lack of domestic discoveries makes gas supply short. The $200 million project will encompass a floating storage regasification

unit with initial capacity of 100 MMcf but expansion potential to 500 MMcf, the energy ministry said. Total will operate the project. Partners will be Shell, Endeavor Energy, state-run Petroci, CI-Energies, SOCAR and Golar LNG.

All Standard Disclaimers & Seller Rights Apply.

Serving the US upstream industry with information, analysis & prospects for sale Volume 26, No. 08

Petro ScoutMay 21, 2015

e&Pwww.plsx.com

REEVES CO., TX PROSPECT ~4,600-Net Acres.DELAWARE BASINObjectives: Wolfcamp (A,B,C)All Depths. All Rights. L80-Acre Down Spacing Pilots Underway.Subsurface Geology Data Available100% OPERATED WI; 75% NRI WOLFCAMPWolfcamp A Approx. IP: ~1,091 BOEDWolfcamp B/C Approx. IP: ~1,190 BOEDWolfcamp EUR’s: 300-450 MBO/WellPKG UPDATED WITH NEW ACREAGEL 5187DV

COLORADO DRILLING PROJECT~43,700 Net Acres.LINCOLN & KIT CARSON COUNTIES MISSISSIPPIAN / PENN TARGETSMiss-Spergen & Penn-Cherokee. <7,500’. LMultipay Objectives. Shallow Depths.Defined By Extensive 3-D Seismic-- MULTIPAY-- Geology & Geophysics Data.100% OPERATED WI; ~80% NRI221 Active Offset Wells, 150 Offset Permits.L 4489DV

FEATURED DEALS

Hess’s Bakken costs falling, targeting $6.0-6.5MM/well

Hess’s lean manufacturing approach in the Bakken is leading to higher production and cheaper wells. Q1 volumes averaged 108,000 boe/d, up 70% YOY and 6% sequentially. A total of 70 wells were brought online in the play during the quarter, down from 96 in Q4. Well costs fell to $6.8 million from $7.1 million in Q4 and

$7.5 million in 1Q14. Hess expects costs to fall further, with 2015 wells averaging $6.0-6.5 million.

During Q1 Hess reduced its Bakken rig count to 12 from 17 at the end of 2014. The company is running currently eight rigs in the play and will continue with that number for the remainder of the year. D&C plans call for 178 wells drilled, 214 completed and 213 turned to sales compared to 261, 230 and 238 last year, respectively.

Noble’s DJ Basin spud-to-rig release days fall to seven In the DJ Basin, Noble Energy has driven spud to rig release times for 4,500-ft

laterals down to just seven days as of Q1, a 23% reduction YOY. Notably, the company drilled a 9,280-ft lateral in just seven days.

“We’re now averaging seven days from spud-to-rig release for a standard lateral length well, almost as fast as we used to drill vertical wells,” said chairman, president

and CEO David L. Stover during a conference call.The company is drilling

wells so quickly that it will end up drilling more wells than anticipated in 2015 and has taken funds from the Marcellus and reallocated them to the DJ. Currently Noble is drilling 70% of the footage of 2014 with 40% of the rigs. The company ended Q1 running four rigs and one completion crew in the DJ. In H2, an additional completion crew will be added as needed.

Reduced drilling times and equipment optimization has led to a 5-15% reduction in costs vs. 2014. Noble foresees further savings via lower service costs and possible use of slickwater, which could save $2.0 million per well.

Parsley’s rookie hz drilling season delivers peer-leading resultsParsley Energy’s well performance has continuously improved since it began

drilling horizontal wells a year and a half ago. The company has drilled 30 Wolfcamp A or B wells thus far and, based on the 30-day data, recently introduced a type curve with

estimated recoveries of 1 MMboe. In the Wolfcamp B during Q1, the 30-day peak IP per 1,000 ft of lateral improved 30% YOY to 231

boe/d. According to COO Matt Gallagher, the improved performance is owed to higher stage density, more slickwater stages, increased proppant per stage and optimal placement of the lateral within the zone.

Parsley’s improved wells are outperforming many of its peers in the Midland Basin. In Upton County, the company’s Wolfcamp B 24-hr IPs are 75% higher than the average when adjusted for lateral length. The Ratliff-28-1 H Wolfcamp B well is credited with flowing the highest reported oil rate of all horizontals in Upton, according to IHS. In Reagan County, data suggests Parlsey’s 24-hr IPs for Wolfcamp B wells are 55% higher than the county average when adjusted for lateral length.

Devon surges past guidance on Eagle Ford performanceCompletion mods push positive results across multiple plays

Fueled by the Eagle Ford, Devon’s oil production exceeded guidance by 12,000 bo/d during Q1 at 272,000 bo/d. Based on the results, the company has increased its oil growth target from 20-25% to 25-30% (270,000 bo/d) for the full year. Q1 overall

volumes also overshot guidance, averaging 685,000 boe/d (60% liquids), up 3% vs. Q4 and 22% YOY. Devon expects volumes to grow 5-10%

this year to an average of 667,000 boe/d. Capex was reduced by $250 million to $3.9-4.1 billion on an improved LOE outlook and accretive midstream transactions.

Since it took control of the Eagle Ford position it acquired from GeoSouthern in March 2014, Devon has grown production in the play 140% to 122,000 boe/d (62% oil). In the last quarter alone volumes jumped 24,000 boe/d, exceeding expectations and creating a bottleneck that will prevent growth in Q2.

Devon’s Eagle Ford drilling is concentrated in the Lower Eagle Ford where the company added 79 new wells to production in Q1.

Eagle Ford output has risen 140% since it took over the assets in March 2014.

Continues On Pg 4

Continues On Pg 21

Continues On Pg 6

Bakken well costs stood at $7.1MM at YE14, already down to $6.5MM in '15.

Continues On Pg 22

Noble nearly drilling horizontals in the time it used to take it to drill a vertical.

Wolfcamp B rates are 75% higher than peers in Upton County.

Rice adds Appalachian firepower, expects 70% output growth.

PetroScout October 11

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MidstreaMNews 12 October 20, 2016

Badlands NGLs to build AO facility on Gulf CoastBadlands NGLs is developing a Gulf Coast alpha olefins (AO) facility that will be

operational in two years. The site has not been chosen, but the company has narrowed its choices to two. Badlands’ facility will produce 93 kt per year of 1-butene and 141 kt per year of 1-hexene. Badlands said its proprietary process will allow it to produce the two products without manufacturing additional non-polyethylene co-monomer AO products. Standard processes produce up to 14 different products.

“The new Badlands AO facility will be the first merchant on purpose 1-butene and 1-hexene fa-cility on the U.S. Gulf Coast,” said CEO William Jeffrey Gilliam.

With the Denver-based company’s proprietary ethylene metathesis technology, 1-butene product will be dimerized from ethylene and 1-hexene will be trimerized from ethylene under a license agreement signed by Badlands. The EPC phase is moving forward on the project with S&B Engineers and Constructors, which Badlands said has recent experience with ethylene

trimerization synthesis of 1-hexene.Badlands has also inked a 15-year

offtake agreement for its products with an unnamed major petrochemical player. Both of the final sites are in close proximity to water transport, so Badlands is eyeing international markets as well as domestic. The project has an undisclosed cost, but the company said it has secured an institutional investor.

Downstream

Annual output will be 93 kt of 1-butene and 141 kt of 1-hexene.

Will be first to produce two AO products without byproducts.

Shell, Iran agree to build petrochem projectsShell and Iran’s National Petrochemical Company have inked an MOU to

jointly develop projects although no specifics as to what those projects will entail have been released. NPC CEO Marzieh Shahdaei, who is also Iran’s deputy oil minister, said his country intends to expand petrochem production from 60 million tons a year

to 160 million tons by 2025, oil ministry news agency SHANA reported.

Shell’s head of Iranian affairs, Hans Nijkamp, said the supermajor and Iran had negotiated for months prior to the MOU. “We believe that we can have joint projects in the petrochemical field with the National Petrochemical Company,” he said.

Although the announcement didn’t come with a specific project attached, deputy oil minister Amir-Hossein Zamaninia said he expected movement soon. “With the wisdom that we see in the people working in our country’s petrochemical industry, without a doubt the projects of this company will be executed sooner than oil and gas projects,” he said, reported SHANA.

Shell seeks to raise $404MM in IPO of Philippines unitShell’s Philippines unit will raise up to $404 million in an IPO, which is at the

high end of guidance and would be the second-largest IPO of the year in the country. BPI Capital COO Reginaldo Cariaso told Reuters that Pilipinas Shell Petroleum will sell up to 291 million shares at $1.39. BPI is the underwriter.

The unit operates one of the country’s two oil refineries. The Tabango refinery in Batangas City has 110,000 bbl/d nameplate capacity. The facility produces gasoline, get fuel, kerosene, diesel, fuel oils, LPG, naphtha and sulphur. A 2015 upgrade enabled it to sell fuels in compliance with the country’s Clean Air Act. The unit also sells performance fuels under the brands Shell V-Power Nitro Plus Racing, Shell V-Power Nitro Plus Diesel and Shell V-Power Nitro Plus Gasoline and main-grade fuels under the brands Shell FuelSave Gasoline and Shell FuelSave Diesel.

Iran intends to expand output to 160 million tons a year by 2025.

Unit operates 110,000 bbl/d Tabango refinery.

Moody’s: Refiners’ EBITDA to decline 15% in 2017

Moody’s expects North American refiners to see their EBITDA decline by more than 15% through next year as inventories remain above historic averages and demand grows slowly. Large inventories will overshadow cost advantages from US shale gas. Additionally, American independents that do not have retail businesses will need to find ways to protect themselves from increasing costs generated by fuel-blending mandates. Moody’s also expects companies to expand midstream logistics rather than processing facilities to improve sourcing.

Global demand for gasoline and distillate products will increase only 1.5% to 96.8 MMbbl/d in 2017, the EIA said, even though prices will be cheaper. In the US, refined product demand will be 10%, which is down from 14% in 2016 and 20% in 2015. Inventories soared on record production from 2015 to summer 2016, and East Coast refiners have the largest burden as they export less.

Meeting renewable fuel obligations has become more costly. Currently, the US mandates that biofuels are 10.1% of total fuel refiners market. Refiners face more costly credits, or Renewable Identification Numbers, required to meet the mandate. Prices are $1 per gallon, or up from 40-60 cents in recent years. Valero, the largest independent, will spend $750-850 million this year.

Moody’s says companies are spending more on midstream than on processing projects as MLPs can offer some protection from falling margins. Though many serve their refining parents, some have third-party revenue sources. Moody’s pointed to Valero, Phillips 66, Marathon Petroleum and Tesoro as having expanded transportation option to deliver crude to their refineries, opening up export markets.

US consumption will be only 10% in 2017, down from 14% this year.

Midstream investments will be up to diversify revenue source, open exports.

International

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Volume 09, No. 14 13 iNfrastructure

■ Russia and Turkey formally agreed to build the TurkStream pipeline under the Black Sea. It remains unknown, however, when construction will begin. Operator Gazprom has permits in hand from Turkish regulators. The 559-mile gas pipeline will link Anapa, Russia, with Kiyikoy, Turkey, transporting 63 Bcm of Siberia-sourced gas each year. Once ashore at Kiyikoy, a pipeline will be built to link TurkStream with a gas pipeline network at Luleburgaz. According to the project website, TurkStream will be the first 32-in. system laid at 2-km depth.

■ Construction is underway on the Albanian section of the Trans Adriatic Pipeline (TAP). This is the second country that the 545-mile pipeline crosses. The $5.7 billion TAP project broke ground in May in Greece. Ultimately, TAP will deliver 10 Bcm of Azeri gas each year to Europe as part of the Southern Gas Corridor, which will total 2,175 miles through seven countries. TAP is the middle section of the system, which also includes the Trans-Anatolia Natural Gas Pipeline (TANAP) and the Southern Caucasus Pipeline (SCP). Altogether, the three represent a $45 billion investment by a consortium led by BP and SOCAR.

International

Antero Midstream (AM; $27.38-Oct. 13; Buy)Updated slides and recent AM underperformance make it worth rehashing our

recent upgrade. AM’s underappreciated leverage to AR production growth and increased completion intensity positions the company for positive revisions to 2017+ earnings

estimates, allowing the company to potentially extend its 28-30% distribution growth through 2020. AR’s plan to ramp from ~110 to 170-180 completions in 2017 while increasing water use per foot should drive meaningful earnings growth

at AM, helping to nearly double freshwater earnings in ‘17 vs. ’16 on top of disproportionate AR volume growth on AM-dedicated acreage. AR management is incentivized to grow AM given that AR derives nearly 35% of its equity value from its ownership in AM, on top of having a large firm transport portfolio as well as personal ownership in the AM GP alongside original private equity backers. —Tudor, Pickering, Holt & Co.

Kinder Morgan (KMI; $21.42-Oct. 11; Buy)Early Q3 softness offers decent entry point for top Midstream pick KMI.

Some chatter on what’s driving recent KMI underperformance but we see little fundamental reason for sell-off. After posting dramatic 24% outperformance vs. the AMZ in Q3, name has seen steady selling pressure over last week. Market may

have some concern over a repeat of the sharp downtick seen with KMI’s Q2 results however we think expectations are more reasonable this go-round, as few investors expect commentary around further deleveraging or pulling forward of returns. KMI currently occupies rarefied air of a nearly 10%

current cash flow yield with contracted backlog driving >30% CF/sh growth by late decade. Sentiment has improved on name but limited market impact as timing is key concern. With Trans Mountain update on the horizon (Dec-16), urgency increasing as company either picks up massive, low-multiple project or finalizes out-year funding plan allowing for a more definitive discussion of leverage trajectory and ultimately buybacks/dividend step-up .—Tudor, Pickering, Holt & Co.

Gunvor to set up shop in HoustonCommodity-trading giant Gunvor has secured a $500 million credit facility to

start up a trading office in Houston to support new US operations. Through the office, Gunvor will trade refined petroleum products, gas and asphalt/bitumen. The 10-person

office will be expanded with the addition of a crude-trading desk, according to Bloomberg. The company said 40% of its oil is sourced from North and South America, and it would

transport US oil from Freeport, Texas, to Panama for storage.

Lead arrangers are Coöperatieve Rabobank U.A., New York Branch, which will also serve as administrative agent, and ABN Amro Capital US. ING Capital, LLC, Natixis, New York Branch, Société Générale and Credit Agricole Corporate and Investment Bank are also lenders. Bank of Texas will be Gunvor’s primary cash-management bank in the US.

The expansion into Houston is a move away from Russian roots and illustrates the trader’s narrowed focus to energy and away from metals. It won’t be Gunvor’s first time in Houston, however, as the firm was in town briefly from 2009-2011 when it acquired Castor but before moving those operations to the Bahamas. Competitors Trafigura and Vitol have offices in Houston. The office is expected to open in June and include ex-Valero Energy and Trafigura trader James Hutchinson.

People & Companies

■ MPLX has named Pamela K.M. Beall as EVP and CFO of the company’s general partner. Beall was EVP of corporate planning and strategy for MPLX, and she replaces Nancy K. Buese, who is leaving to pursue another opportunity. CEO Gary R. Heminger said Beall had significant financial experience, including accounting and commercial roles at MPLX parent Marathon Petroleum.

■ Phillips 66’s board of directors has elected Denise L. Ramos and Gary K. Adams as independent directors, bringing board membership to 10. Ramos, who is

CEO of ITT, will serve on the following committees:

Audit and Finance, Nominating and Governance and Public Policy. Adams, chief adviser of chemicals for IHS, will serve on the Human Resources and Compensation and the Public Policy committees.

40% of crude originates from North, South America.

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What the Analysts are Saying about Midstream

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MidstreaMNews 14 October 20, 2016

Magellan Midstream Partners (MMP; $69.92-Sept. 28; Overweight; PT: $82)Ample Backlog, Room to Run. Organic project backlog and competitive currency

support positive outlook. We continue to view MMP as a high quality investment idea in the MLP sector and believe the Partnership warrants its premium equity yield of 4.7%

(vs. 7.2% sector average) due to solid growth visibility (8% 3-year CAGR), stable cash flows (85% fee-based), no GP IDRs and a BBB+ credit rating. In an environment in which wide bid-ask spreads render many potential

acquisitions prohibitively expensive, MMP’s growth is supported by a multi-billion dollar organic project backlog with an avg EBITDA multiple of 8x by our estimates. MMP currently has $1.3B of projects under construction through 2018, plus a $1.5B+ backlog of projects under development. Given its healthy balance sheet (PF leverage of 3.1x as of 2Q) and IG credit rating, we believe MMP will fund its projects primarily with debt while still maintaining its leverage target of sub-4x. We reiterate our $82 PT based on forward 12-month distribution run rate of $3.56 and 4.3% yield.—Barclays

Noble Midstream Partners (NBLX; $27.71-Oct. 11; Overweight)We are initiating coverage of NBLX with an OW rating and a $35 price target.

NBLX is a high-growth, relatively stable gathering and processing MLP backed by a leading oil and gas producer parent, Noble Energy Inc (NBL). Our 20% distribution

CAGR estimate (through 2019) is supported by base volume growth, drop downs, and organic projects. Stability is underpinned by long-term, fee-based contracts with acreage dedications. NBLX currently trades at a discount on

a yield basis to the sponsored G&P MLPs peer group, despite offering a slightly better growth outlook. The Partnership trades at a premium to the broader MLP coverage universe, which we believe is warranted due to its high growth visibility and cash flow stability. Our $35 PT is based on a forward distribution run rate of $1.58 and 4.5% target yield. —Barclays

Par Pacific Holdings (PARR; $13.83-Oct. 13; Buy; PT: $22)Lowering Q3 estimates on higher expenses. We are updating our Q3:16 estimates

to reflect higher-than-expected expenses from the downtime of the Hawaiian refinery and those associated with maintenance on the SPM. Our thesis has been that there are far too many things happening in Q3:16 (Hawaiian refinery down, WRC closing during the quarter, SPM maintenance...) to use 2016 as

a valuation metric. Our 2017 estimates still support a valuation of $22 on a sum-of-the-parts methodology. We maintain our Buy rating. Our Q4:16 and 2017 forecasts are unaffected. We continue to rate PARR a Buy with a $22 price target.—Seaport Global

Phillips 66 Partners (PSXP; $47.44-Oct 11; Equal Weight)Wrapping up the year with a $1.3 billion dropdown. The acquisition implies

a 2017E EBITDA multiple of ~8.7x on 2017E EBITDA of $150 million and will be financed with a combination of debt and $196 million of PSXP units issued to the

parent (which implies roughly an 85/15 debt/equity mix). Size and terms of drop down provide greater visibility to distribution growth

target: The size of the drop was larger than we anticipated while the multiple was slightly more favorable than our expected 9.0x and should provide greater visibility to PSXP’s targeted 30% distribution growth CAGR through 2018. The transaction was also funded with more debt than we had modeled, so leverage has crept higher to ~3.8x, but is still within the 3.0 to 4.0x debt/EBITDA target range. Post the drop down, we estimate adjusted EBITDA of ~$803mm in 2017 (vs. $738mm previously) and $1.1 billion by 2018. We aren’t changing our distribution growth estimates of 26% this year and 24% next year, but due to the larger size of this dropdown and the lower-than-expected equity issuance, our coverage has improved from 1.30x to 1.45x. —Barclays

What the Analysts are Saying about Midstream ■ Stonepeak Infrastructure

Partners welcomes William Schleier as an associate. Prior to joining Stonepeak, Schleier served as an analyst of investment banking at CitiGroup.

■ Tailwater Capital has committed $100 million to startup Producers Midstream, which will focus on acquisition opportunities in Texas, Oklahoma and New Mexico. CEO Jim Bryant will lead the company. He was co-founder of Endevco, Regency Gas Services and Cardinal Midstream. His team will include CFO Hudson White; Matt Flory, VP of business development and commercial; James Hegar, VP of engineering and operations; and Chad Choate, VP of business development and commercial.

■ Tellurian Investments has named R. Keith Teague as EVP and COO. Previously Teague was EVP of asset group for Cheniere Energy, where Tellurian chairman Charif Souki was ousted earlier this year before founding Tellurian. The company aims to build 26 mtpa Driftwood LNG near Lake Charles, Louisiana.

■ Three of the Williams Cos. board members have voluntarily chosen not to stand for reelection in November. Juanita H. Hinshaw, Joseph Cleveland and John A. Hagg were considered independent directors. Four board members will stand for reelection. Williams says it still plans to nominate two new independent directors prior to the election.

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Volume 09, No. 14 15 iNfrastructure

EASTERN & APPALACHIAPENNSYLVANIA & OHIO PROPERTY1,120-Total Wells. ~211,000-Net Acres.APPALACHIAN GAS BASIN PP1,084-Operated Wells. 36-NonOperated.Varying OPERATED WI & ORRINet Projected Prod: ~6 BOPD & ~6 MMCFD2017 Projected Cash Flow: $175,000/Mn312-Miles Of Field Gathering Lines.Gas Storage Opportunity. APPALACHIANCONTACT AGENT - POST BID STATUSPP 5981RR

ROCKIESROCKIES MIDSTREAM ASSETS~19-Miles Of Gathering System.COLORADO & WYOMING GSystem Is To Williams/Questar Pipeline.100% Ownership Available. GATHERINGReplacement Cost: $6,972,800 ASSETSCONTACT SELLER FOR MORE INFOG 4870

WEST COASTWEST COAST PROPERTY PACKAGE11-Wells.GAS PROPERTY Producing Gas From Shallow Intervals.Significant Upside Potential. PPOPERATED WI FOR SALECurrent Net Production: ~1.7 MMCFD >1.5Net Cash Flow:~$150,000/Mn (3-Mn Avg) MMCFD(Cash Flow Is Both Wells & Gathering)Gathering Infrastructure In Place.Advantageous Sales Contract.PP 5608DV

WANTEDWANTED: EAST TEXAS MIDSTREAMSeeking Midstream Assets.RRC DISTRICT #6 WPreferred Gas Gathering Assets----With SWD Handling. MIDSTREAMCan Buy Midstream System With----Underlying Dedicated Production.CASH-READY BUYERSeller Can Retain Operatorship If Desired.W 6667G

WANTED: MIDSTREAM ASSETSGathering Systems & PipelinesOKLAHOMA & TEXAS WWill Also See New Mexico, Colorado,Louisiana & Wyoming Areas.Assets Outside Those Areas Considered.Also Looking At Processing Plants.JVs With Upstream Operators. MIDSTREAMCASH-READY BUYERW 5502G

MIDCONTINENTKIOWA CO., KS PROPERTY2-Wells. 320-Total Acres.MISSISSIPPIAN GAS TREND PPDrill Depth 4,600 Feet.1-Producing Well. 1-Shut In Well. ~100 100% OPERATED WI; 87.5% NRI MCFDGross Production: 50-100 MCFDCONTACT SELLER FOR MORE INFOPP 3560

OKLAHOMA ASSETS FOR SALEProducing Wells & HBP Acreage.STACK MULTIPAY POTENTIAL PPMeramec, Osage, Hunton, Woodford ---- & Mississippian Potential >6.5Mostly OPERATED WI Available. MMCFDSignificant Production Majority Gas.PORTION OF PKG HAS SOLD. 04/2016CONTACT AGENT FOR MORE INFOPP 4450DV

OKLAHOMA PROPERTY SALE~143-Producing Wells. ~123-NonProducing.ARKOMA BASIN PPProven Behind Pipe Zones: Atoka, Booch,Brazil, Cromwell, Harthshorn, Panola,Spiro & Wapanucka ~3,660OPERATED WI AVAILABLE MCFD6-Mn Avg Gross Prod: 3,661 MCFD9-Mn Avg Net Income: $62,182/MonthLifting Cost Reduction Potential & LiftOptimizationCONTACT AGENT FOR UPDATEPP 5627DV

SOUTHERN OKLAHOMA ASSETS92-Total Wells.ATOKA, LATIMER & PITTSBURG COS. PPARKOMA BASIN ORRI, MI & Surface Interest Available MIDCONVarying OPERATED & NonOperated WI6-Mn Avg Gross Production: 7,761 MCFD12-Mn Avg Net Income: $77,269/MonthCONTACT AGENT FOR UPDATEPP 5842RR

SOUTHERN OKLAHOMA PROPERTY165-Total Wells.HASKELL, LATIMER, MCINTOSH, PPPITTSBURG & SEQUOYA COUNTIESARKOMA BASIN MIDCONOPERATED, NonOperated WI & ORRI6-Mn Avg Gross Production: 8,034 MCFD12-Mn Avg Net Income: $75,553/MonthCONTACT AGENT FOR UPDATEPP 5872RR

ARK-LA-TEXSTRATEGIC PIPELINE RIGHT-OF-WAY65-Mile Corridor. +/- 20,750 RODS.EAST TEXAS GSHELBY, RUSK, NACOGDOCHES ------ & ANGELINA COUNTIES R-O-WExposure to Cotton Valley DevelopmentContiguous Recorded, Valid Rights-of-Way~95% of ROW Contains 8 Steel --Pipeline, Could be Used as Conduit for-- New 6-in. Pipeline Installation.ROW’S Allow for New Pipeline ---- Construction of Any Diameter SizeOffset Operators: Anadarko, EP Energy ---- and BHP BillitonReady For New Pipeline ConstructionG 1964PL

HAYNESVILLE ASSETS FOR SALE~170-PDP Wells. ~83,000-Net Acres.TEXAS & LOUISIANA PPPrimary Objs: Haynesville & Bossier>700 Gross Operated Drilling Locations>60 Refracture Candidates. >35Acreage 97% Held By Production. MMCFEDEst June 2016 Prod: ~36 MMCFEDProduction 90% Gas.Net Operating Cash Flow: ~$2,000,000/MnMidstream Infrastructure In Place.CONTACT AGENT - POST BID STATUSPP 4653DV

PERMIANGAINES CO., TX MIDSTREAM ASSETGathering System. Pipelines & Plants.CONVERSION POTENTIAL GCurrently Gathering Yates Production.Assets Can Be Used for Other Horizons,High Pressure Gas Transmission,Crude Gathering, CO2 Transmission, NGL,Or Water Gathering/Disposal. MIDSTREAMSEEKING CASH PURCHASECan Handle Up To 15 MMCFD Capacity.CONTACT AGENT FOR MORE INFOG 1879PL

MIDCONTINENTNORTH TEXAS PROPERTY FOR SALE~150-Wells. ~80,000-Net Acres.JACK, PALO PINTO & CLAY COUNTIES PPFORT WORTH BASINTargets: Marble Falls, Barnett, Strawn, ~3,000Conglomerate & Caddo Formations BOED850+ Vert & HZ Marble Falls Locations~100% OPERATED WI; ~75% NRINet Production: ~3,000 BOEDTotal 3P Reserves: 215 MMBOE400+ Miles Of Gas/Water Flow Lines &Pipeline In PlaceCONTACT AGENT FOR UPDATEPP 5626DV

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