Atlas Pipeline Partners LP (APL) announced 2Q11 results, reporting distributable cash flow (DCF) of $29.9 million versus $26.5 million the prior year and $26.8 million in 1Q11. Recurring adjusted EBITDA totaled $39.8 million compared to $52.8 million the prior year and $38.6 million in 1Q11.
DCF was higher than the previous year partially due to reduced leverage costs associated with the liquidation of its interest in its Elk City system and the related deleveraging. As previously announced, the partnership increased its quarterly distribution per unit (DPU) to $0.47 from $0.40 the prior period as it returns to paying a sustainable distribution.
The partnership is essentially running at 100 percent capacity across its systems and has planned expansions for three processing plants, which will come on line by 2012 to support its customers anticipated volume growth. As a result, we anticipate volumes will continue to increase through 2012. The partnership did note that it is leaving some liquids in the natural gas given the lack of NGL takeaway capacity from West Texas. Subsequent to the quarter end the partnership announced it exercised the accordion feature on its revolver and increased availability to $450 million from $350 million. We view this as necessary in order support its planned capacity additions. Longer term, we view the capacity additions as supporting continued DCF growth.
We are adjusting estimates for Natural Resource Partners L.P. (NRP – Buy – $28.45) following the partnership’s report of 2Q11 EPU (earnings per unit) of $0.48 vs. our estimate of $0.44 and Street consensus of $0.44. NRP’s 2Q11 results were driven by stronger coal royalty volumes and average royalty per ton in Northern and Central Appalachia versus our estimates, partially offset by weaker results from the Illinois Basin and the Powder River Basin due to Midwestern region flooding. NRP declared a quarterly distribution of $0.54 per unit in 2Q11 that was unchanged from 1Q11’s distribution.
We are maintaining our 2011 EPU estimate of $1.77 versus the Street consensus of $1.73, reflecting the $0.04 EPU beat in 2Q11 that is offset by weaker assumed coal royalty production and lower average royalty per ton in 2H11 on an assumed mix-shift toward thermal coal. For 2011, we estimate distributions of $2.16 per unit (versus Street consensus of $2.17), below our previous estimate of $2.22 per unit. Our $2.16 estimate is even with the $2.16 paid in 2010. Our assumption is that distributions remain at $0.54 through 2011 as NRP continues to invest capital in acquiring coal reserves in the Illinois Basin under its agreement with the Cline Group.
We use a target yield methodology to arrive at our target price of $37/unit, which we obtain by applying a 6.0 percent yield to our forward four quarter DPU (distribution per unit) estimate of $2.19. NRP’s peer group of coal-related MLPs trades at an average current yield of 7.9 percent (for PVR, RNO, ARLP and OXF). We assign a lower target yield to NRP due to the partnership’s lack of exposure to direct coal mining operating risks.
Penn Virginia Corporation (PVA) reported in-line quarterly production, but lower than expected CFPS/EPS (cash flow per share/earnings per share) primarily due to higher costs. Additionally, the company is lowering midpoint production guidance by almost 5 percent to 48.5-50.5 bcfe (billions of cubic feet equivalent) and increasing midpoint capex (capital expenditures) guidance by about 7 percent to $360-380 million … [W]e are looking for the Eagle Ford to be the driver to turn this name around and, on that front, the results were positive.
The company’s average IP (initial production) on its second batch of six wells was 1,169 boe/d (barrels of oil equivalent per day) versus 1,040 boe/d for the first six wells that were previously released. Additionally, the acreage position has been increased from 12,700 to 13,900 net acres at an attractive cost of $4,000/acre. With three rigs running in the Eagle Ford, and with well count expected to increase from 12 to 34 gross wells by year end, the company’s Eagle Ford production will increase from 5 mboe/d (thousand barrels of oil equivalent per day) currently to 8 mboe/d, and the company is estimating that its liquids ratio will increase from 24 percent in 2Q to about 40-45 percent at yearend 2011.
Therefore … given the current valuation of 3.2x 2012 EV/EBITDA (enterprise value divided by earnings before interest, taxes, depreciation and amortization) and the fact that the driver to turn the company around (Eagle Ford) is performing well, we maintain our Buy rating and highlight the name for value investors looking for turnaround stories. Our $18 target price reflects a 2012 target EV/EBITDA multiple of 4.0x.
Macquarie Equities Research
We are encouraged by Shell’s upstream results, and we anticipate similar margin capture over the rest of 2011 (and beyond) as the new mega-projects ramp-up. We think free cash flow generation should reach approximately U.S. $15 billion in 2012, about 11 percent of current market capitalization. Trading on 6.3x 2012E earnings compared to a peer group average of 7.0x, Shell remains one of our most preferred names through 2H11. As the company further demonstrates growth, we believe it will move to a premium valuation.
2Q11 clean net income of U.S. $6.4 billion was 1 percent light on consensus and 6 percent below our estimate. Upstream earnings of U.S. $5.4 billion were essentially in-line with our forecast (and 2 percent ahead of consensus). While 2Q11 production of 3,046 kboepd (kilo barrel of oil equivalent per day) was down 2 percent year-over-year, realizations (both liquids and gas) were better than expected and clean net income of U.S. $1.6bn in the Integrated Gas division was up 111 percent year-over-year. Upstream net income per barrel of U.S. $19.6/boe (barrel of oil equivalent) in 2Q11 was marginally ahead of our estimates, an increase of circa 33 percent on 1Q11.
While this strong upstream result was aided by higher trading contributions, we take encouragement from signs that the major projects in Shell’s upstream portfolio are progressing to plan. In particular we note LNG (liquified natural gas) sales volumes of 4.81mt (metric tons) reflecting the successful ramp-up of Qatargas 4 during the quarter.
Given our underlying macro assumptions and expectations for a tightening LNG market in Asia-Pacific, we believe similar margins are sustainable over the remainder of 2011 (and beyond). This strong upstream result is especially stark in contrast to BP’s near-term operational issues in the Gulf of Mexico.
We are encouraged by Shell’s upstream results, and we anticipate similar margin capture over the rest of 2011 (and beyond) as the new mega-projects ramp-up. We think free cash flow generation should reach about U.S. $15 billion in 2012, about 11 percent of current market capitalization.
Trading on 6.3x 2012E earnings compared to a peer group average of 7.0x, Shell’s remains one of our most preferred names through 2H11. As the company further demonstrates growth, we believe it will move to a premium valuation.
Southwest Gas Corp. (SWX) realized adjusted 2Q EPS of $0.03, excluding a $2.6 million increase in COLI (corporate owned life insurance) value, in-line with our $0.03 estimate and above the Street’s $0.02 loss-per-share mean estimate. Better than expected NPL (Construction Co., SWX’s construction services segment) results offset modestly lower than anticipated utility gross profit to produce the in-line EPS.
On the (recent earnings) call, management noted its favorable dividend outlook given the progress of Arizona (AZ) rate case proceedings, recent credit rating upgrades, declining debt costs, and a low payout ratio.
Settlement hearings began this week on the two settlement proposals before the Arizona Corporation Commission (ACC). Alternative “A” proposes $54.9 million in rate relief, a 9.75 percent ROE and a partially decoupled rate structure (with weather normalization and lost revenues provisions), while option “B” supports $52.6 million in relief, a 9.5 percent ROE, a fully decoupled rate design and a 5.5-year stay out provision. On the [recent earnings] call, management stated a preference for option “B” given its fully decoupled rate design and expects rates effective January 1, 2012.
On the call, management noted its favorable dividend outlook given the progress of Arizona rate-case proceedings, recent credit rating upgrades, declining debt costs and a low payout ratio. n